System and method for determining torsion using an opto-analytical device

ABSTRACT

In one embodiments, a method includes drilling a wellbore in a formation with a drilling tool. The method further includes receiving electromagnetic radiation using an opto-analytical device 1000 coupled to the drilling tool. The method also includes determining torsion associated with drilling the wellbore based on the received electromagnetic radiation.

TECHNICAL FIELD

The present disclosure relates generally to downhole drilling tools and,more particularly, to a system and method for determining torsion in adrilling tool using an opto-analytical device.

BACKGROUND

Various types of downhole drilling tools including, but not limited to,rotary drill bits, reamers, core bits, and other downhole tools havebeen used to form wellbores in associated downhole formations. Examplesof such rotary drill bits include, but are not limited to, fixed cutterdrill bits, drag bits, polycrystalline diamond compact (PDC) drill bits,and matrix drill bits associated with forming oil and gas wellsextending through one or more downhole formations. Fixed cutter drillbits such as a PDC bit may include multiple blades that each includemultiple cutting elements.

In typical drilling applications, a PDC bit may be used to drill throughvarious levels or types of geological formations with longer bit lifethan non-PDC bits. Typical formations may generally have a relativelylow compressive strength in the upper portions (e.g., shallower drillingdepths) of the formation and a relatively high compressive strength inthe lower portions (e.g., deeper drilling depths) of the formation.

One or more drilling characteristics may affect the process of drillingin a formation. These drilling characteristics may include properties ofthe formation itself (e.g., porosity, plasticity, density, rockstrength, rock type and composition (e.g. shale, sandstone, limestone,etc.)), changes in the formation being drilled, the presence of types offluids in the formation, the presence of brines in the formation, thepresence of hydrocarbons (e.g., oil, natural gas) in the formation,changes in concentration of gases as the formation is being drilled,temperatures of components of the drilling tool, vibration of thedrilling tool and drill string, torsion, cutting element wear, depth ofcut control, cutting sizes, etc.

SUMMARY

In one embodiments, a method includes drilling a wellbore in a formationwith a drilling tool. The method further includes receivingelectromagnetic radiation using an opto-analytical device coupled to thedrilling tool. The method also includes determining torsion associatedwith drilling the wellbore based on the received electromagneticradiation.

In some embodiments, determining torsion associated with drilling thewellbore based on the received electromagnetic radiation may includesdetecting a plurality of deviations in the electromagnetic radiationindicating a identifiable feature in a wellbore, determining a velocityof the drill bit based on a period between detections of the deviations,and determining deviations in the velocity of the drill bit. In someembodiments, the identifiable feature is a physical feature in thewellbore. In certain embodiments, the deviations indicating aidentifiable feature in the wellbore comprise peaks in an amount ofelectromagnetic radiation being received at a particular point in time.

In particular embodiments, the opto-analytical device comprises a firstsensor and a second sensor coupled to the drilling tool, each sensordisplaced longitudinally along the drilling tool with respect to oneanother, and determining torsion associated with drilling the wellborebased on the received electromagnetic radiation comprises determining anoffset between the first and second sensors. In such embodiments,determining an offset between the first and second sensors may be basedon positions of the first and second sensors with respect to anidentifiable feature in the wellbore. Alternatively, determining anoffset between the first and second sensors may be based on positions ofthe first and second sensors with respect to an identifiable feature onthe drilling tool.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and itsfeatures and advantages, reference is now made to the followingdescription, taken in conjunction with the accompanying drawings, inwhich:

FIG. 1 illustrates an example embodiment of a drilling system inaccordance with some embodiments of the present disclosure;

FIG. 2A illustrates an isometric view of a rotary drill bit orientedupwardly in a manner often used to model or design drill bits inaccordance with some embodiments on the present disclosure,

FIG. 2B illustrates an example graph of output torque of a motor as afunction of rotational speed, fluid speed, and differential pressure;

FIG. 3 illustrates a block diagram of an opto-analytical deviceconfigured to determine one or more characteristics of a sample inaccordance with some embodiments of the present disclosure;

FIG. 4 illustrates a cross-sectional view of an example configuration ofdrill bit 101 in accordance with some embodiments of the presentdisclosure;

FIG. 5 illustrates an example embodiment of a drill bit integrated withone or more opto-analytical devices in accordance with some embodimentsof the present disclosure;

FIG. 6 illustrates an example method for analyzing cuttings associatedwith drilling a wellbore in accordance with some embodiments of thepresent disclosure;

FIG. 7A illustrates an example embodiment of a temperature sensorincluding an opto-analytical device in accordance with some embodimentsof the present disclosure;

FIG. 7B illustrates example spectral signatures of a material atdifferent temperatures in accordance with some embodiments of thepresent disclosure;

FIG. 7C illustrates an example configuration of temperature sensors withcutting elements to determine one or more drilling characteristics basedon the temperature of cutting elements in accordance with someembodiments of the present disclosure;

FIG. 7D illustrates example plots and of the temperatures of cuttingelements as a function of time, in accordance with some embodiments ofthe present disclosure;

FIG. 8 illustrates an example method for determining one or moredrilling characteristics based on temperature in accordance with someembodiments of the present disclosure;

FIG. 9 illustrates and example configuration of a bottom hole assemblyincluding opto-analytical devices configured to determine torsion of thedrilling tool in accordance with some embodiments of the presentdisclosure;

FIG. 10 illustrates an example method for determining torsion of adrilling tool in accordance with some embodiments of the presentdisclosure;

FIG. 11 illustrates an example embodiment of a gap sensor in accordancewith some embodiments of the present disclosure;

FIGS. 12A-12C illustrate an example of bit whirl of a drill bit in awellbore, in accordance with some embodiments of the present disclosure;

FIG. 12D illustrates example plots of points that indicate the bit walkof two drill bits in accordance with some embodiments of the presentdisclosure;

FIG. 13A illustrates a cross-sectional view of an example configurationof a drill bit including gap sensors in accordance with some embodimentsof the present disclosure;

FIG. 13B illustrates example plots of gaps between a drill bit and awellbore over time in accordance with some embodiments of the presentdisclosure;

FIG. 14 illustrates an example configuration of a drill bit including agap sensor configured to detect the depth of cut of a cutting element inaccordance with some embodiments of the present disclosure;

FIG. 15 illustrates an example configuration of a drill bit including agap sensor configured to detect the wear of a cutting element inaccordance with some embodiments of the present disclosure;

FIG. 16 illustrates a flow chart of an example method for determining agap between objects in accordance with some embodiments of the presentdisclosure;

FIG. 17A illustrates an example embodiment of an accelerometerconfigured to determine acceleration of a drilling tool using anopto-analytical device in accordance with some embodiments of thepresent disclosure;

FIG. 17B illustrates another embodiment of an accelerometer configuredto determine acceleration of a drilling tool using an opto-analyticaldevice in accordance with some embodiments of the present disclosure;

FIG. 18 illustrates an example configuration of an accelerometerintegrated with a drill bit along the rotational axis of the drill bitsuch that accelerometer may detect axial vibration of the drill bit inaccordance with some embodiments of the present disclosure; and

FIG. 19 illustrates an example configuration of accelerometersintegrated with a drill bit to determine the rotational speed of thedrill bit in accordance with some embodiments of the present disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure and its advantages may beunderstood by referring to FIGS. 1 through 19, where like numbers areused to indicate like and corresponding parts.

FIG. 1 illustrates an example embodiment of a drilling system 100configured to drill a wellbore 114 into a geological formation inaccordance with some embodiments of the present disclosure. Whiledrilling through a geological formation, one or more drillingcharacteristics may affect the performance of drilling system 100.Additionally, modifications may be made to the drilling of wellbore 114based on the presence of certain drilling characteristics. Further, thedesign of one or more drilling tools (e.g., drill bit, reamer,stabilizer, hole enlarger, etc.) of drilling system 100 may bedetermined based on the drilling characteristics. These drillingcharacteristics may include properties of the formation itself (e.g.,porosity, permeability, plasticity, density, rock strength, stress,etc.), changes in the formation being drilled (such as bedding planes,fractures, compositional elements, etc.), the presence of types offluids in the formation, the presence of brines in the formation, thepresence of hydrocarbons (e.g., oil, natural gas) in the formation,changes in concentration of gases in the formation, temperatures ofcomponents of the drilling tool, vibration of the drilling tool anddrill string, weight on bit, torque on bit, bit rotational speed, rateof penetration, bit mechanicals, specific energy, torsion, bit whirl,bit walk, bit tilt, cutting element wear, depth of cut, cutting sizes,drilling fluid types and speed in the hole annuals, rock chemistryand/or composition, texture, water, salt, pH, impurities, temperature,pressure etc.

In many instances it may be advantageous to measure one or more drillingcharacteristics during the process of drilling wellbore 114. Measuringone or more drilling characteristics during the process of drillingwellbore 114 may allow for a more accurate representation of the effectsthat drilling characteristics may have on the drilling process anddrilling tools of drilling system 100. For example, measuring drillingtool properties (e.g., the temperature, vibration, torsion, wear, etc.of drilling tools) during drilling may allow for a more accurateanalysis of the physical conditions and strain that may affect thedrilling tools of drilling system 100. Additionally, measurements offormation properties (e.g., rock strength, stress, porosity, density,plasticity, rock type, and rock composition) during the process ofdrilling through the formation may also provide a more accurate analysisof the physical conditions that may affect the drilling tools anddrilling system 100. Further, measuring the presence of certain gases ator near the end of wellbore 114 may allow for preparations at well site106. For instance, the detection of certain gases at or near the end ofwellbore 114 may require different preparations (e.g. safety) at wellsite 106.

Accordingly, the drilling tools may be modified for improved performancethrough a more accurate representation of the physical conditions thatmay affect the drilling tools. For example, an analysis of the wear of adrilling tool during drilling and an analysis of the rock strength ofthe formation being drilled may allow for modifications of the design ofthe drilling tool (or other drilling tools to be used in the samelocation) to better cut through a formation having that particular rockstrength. Additionally, an analysis of the measured temperature duringdrilling may allow for determining the particular temperature tolerancesof the drilling tools of drilling system 100. More examples ofmodifications that may be made with respect to certain drillingcharacteristics are discussed in detail below.

Measuring drilling characteristics during the process of drillingwellbore 114 may also allow for modifications to be made to the processof drilling wellbore 114 based on one or more drilling characteristics.For example, measuring an increased presence of a hydrocarbon (e.g.,oil, natural gas) at or near the end of wellbore 114 may indicate that adrilling tool (e.g., drill bit) has reached a hydrocarbon reservoir.

As described in further detail below, in accordance with one or moreembodiments of the present disclosure, one or more opto-analyticaldevices may be configured to measure one or more drillingcharacteristics. The one or more opto-analytical devices may beintegrated with one or more drilling tools of drilling system 100 suchthat the one or more opto-analytical devices may measure the one or moredrilling characteristics at or near the end of wellbore 114 during theprocess of drilling wellbore 114. As discussed in further detail withrespect to FIG. 3, an opto-analytical device may be configured tomeasure a drilling characteristic based on the interaction ofelectromagnetic radiation with the formation and/or drilling tool.Therefore, the one or more opto-analytical devices integrated with theone or more drilling tools may allow for measuring one or more drillingcharacteristics during the process of drilling wellbore 114, which mayallow for better design of drilling tools and desired modifications tothe drilling of wellbore 114.

Drilling system 100 may include a well surface or well site 106. Varioustypes of drilling equipment such as a rotary table, drilling fluid pumpsand drilling fluid tanks (not expressly shown) may be located at a wellsurface or well site 106. For example, well site 106 may include adrilling rig 102 that may have various characteristics and featuresassociated with a “land drilling rig.” However, downhole drilling toolsincorporating teachings of the present disclosure may be satisfactorilyused with drilling equipment located on offshore platforms, drill ships,semi-submersibles and drilling barges (not expressly shown).

Drilling system 100 may include a drill string 103 associated with drillbit 101 that may be used to form a wide variety of wellbores or boreholes such as generally vertical wellbore 114 a or generally horizontalwellbore 114 b as shown in FIG. 1. Various directional drillingtechniques and associated components of a bottom hole assembly (BHA) 120of drill string 103 may be used to form horizontal wellbore 114 b. Forexample, lateral forces may be applied to BHA 120 proximate kickofflocation 113 to form horizontal wellbore 114 b extending from generallyvertical wellbore 114 a.

BHA 120 may be formed from a wide variety of components configured toform a wellbore 114. For example, components 122 a, 122 b and 122 c ofBHA 120 may include, but are not limited to, drill bits (e.g., drill bit101), drill collars, rotary steering tools, directional drilling tools,downhole drilling motors, reamers, hole enlargers or stabilizers. Thenumber of components such as drill collars and different types ofcomponents 122 included in BHA 120 may depend upon anticipated downholedrilling conditions and the type of wellbore that will be formed bydrill string 103 and rotary drill bit 101. As discussed in furtherdetail below, one or more opto-analytical devices may be integrated withone or more components of BHA 120 such that one or more drillingcharacteristics may be measured in wellbore 114 during the process ofdrilling wellbore 114.

Wellbore 114 may be defined in part by a casing string 110 that mayextend from well surface 106 to a selected downhole location. Portionsof a wellbore 114, as shown in

FIG. 1, that do not include casing string 110 may be described as “openhole.” Various types of drilling fluid may be pumped from well surface106 through drill string 103 to attached drill bit 101. Such drillingfluids may be directed to flow from drill string 103 to respectivenozzles (depicted as nozzles 156 in FIG. 2) passing through rotary drillbit 101. The drilling fluid may be circulated back to well surface 106through an annulus 108. Annulus may refer to the space between theoutside of the drill pipe or drill collars and the casing or wellbore,and may be defined in part by outside diameter 112 of drill string 103and inside diameter 118 of wellbore 114 a. Inside diameter 118 may bereferred to as the “sidewall” of wellbore 114 a. Annulus 108 may also bedefined by outside diameter 112 of drill string 103 and inside diameter111 of casing string 110.

Drilling system 100 may also include a drill bit 101. Drill bit 101 maybe any of various types of drill bits including percussion bits, rollercone bits, coring bits and fixed cutter drill bits. Drill bit 101 may bedesigned and formed in accordance with teachings of the presentdisclosure and may have many different designs, configurations, and/ordimensions according to the particular application of drill bit 101. Asdisclosed in further detail below with respect to FIGS. 3-19, one ormore opto-analytical devices (not expressly shown) may be integratedwith drill bit 101 such that the one or more opto-analytical devices maymeasure one or more drilling characteristics at or near the end ofwellbore 114 during the process of drilling wellbore 114.

FIG. 2 illustrates an isometric view of a rotary drill bit 101 orientedupwardly in a manner often used to model or design drill bits inaccordance with some embodiments on the present disclosure. In thepresent embodiment, drill bit 101 may be any of various types of fixedcutter drill bits, including PDC bits, drag bits, matrix drill bits,and/or steel body drill bits operable to form wellbore 114 extendingthrough one or more downhole formations. Drill bit 101 may be designedand formed in accordance with teachings of the present disclosure andmay have many different designs, configurations, and/or dimensionsaccording to the particular application of drill bit 101.

Drill bit 101 may include one or more blades 126 (e.g., blades 126 a-126g) that may be disposed outwardly from exterior portions of rotary bitbody 124 of drill bit 101. Rotary bit body 124 may have a generallycylindrical body and blades 126 may be any suitable type of projectionsextending outwardly from rotary bit body 124. For example, a portion ofblade 126 may be directly or indirectly coupled to an exterior portionof bit body 124, while another portion of blade 126 may be projectedaway from the exterior portion of bit body 124. Blades 126 formed inaccordance with teachings of the present disclosure may have a widevariety of configurations including, but not limited to, substantiallyarched, helical, spiraling, tapered, converging, diverging, symmetrical,and/or asymmetrical.

In some cases, blades 126 may have substantially arched configurations,generally helical configurations, spiral shaped configurations, or anyother configuration satisfactory for use with each downhole drillingtool. One or more blades 126 may have a substantially archedconfiguration extending from proximate rotational axis 104 of drill bit101. The arched configuration may be defined in part by a generallyconcave, recessed shaped portion extending from proximate bit rotationalaxis 104. The arched configuration may also be defined in part by agenerally convex, outwardly curved portion disposed between the concave,recessed portion and exterior portions of each blade which correspondgenerally with the outside diameter of the rotary drill bit.

Each of blades 126 may include a first end disposed proximate or towardbit rotational axis 104 and a second end disposed proximate or towardexterior portions of drill bit 101 (e.g., disposed generally away frombit rotational axis 104 and toward uphole portions of drill bit 101).The terms “uphole” and “downhole” may be used to describe the locationof various components of drilling system 100 relative to the bottom orend of wellbore 114 shown in FIG. 1. For example, a first componentdescribed as uphole from a second component may be further away from theend of wellbore 114 than the second component. Similarly, a firstcomponent described as being downhole from a second component may belocated closer to the end of wellbore 114 than the second component.

Blades 126 a-126 g may include primary blades disposed about the bitrotational axis. For example, in FIG. 2A, blades 126 a, 126 c, and 126 emay be primary blades or major blades because respective first ends 141of each of blades 126 a, 126 c, and 126 e may be disposed closelyadjacent to associated bit rotational axis 104. In some embodiments,blades 126 a-126 g may also include at least one secondary bladedisposed between the primary blades. Blades 126 b, 126 d, 126 f, and 126g shown in FIG. 2 on drill bit 101 may be secondary blades or minorblades because respective first ends 141 may be disposed on downhole end151 a distance from associated bit rotational axis 104. The number andlocation of secondary blades and primary blades may vary such that drillbit 101 includes more or less secondary and primary blades. Blades 126may be disposed symmetrically or asymmetrically with regard to eachother and bit rotational axis 104 where the disposition may be based onthe downhole drilling conditions of the drilling environment. In somecases, blades 126 and drill bit 101 may rotate about rotational axis 104in a direction defined by directional arrow 105.

Each blade may have a leading (or front) surface disposed on one side ofthe blade in the direction of rotation of drill bit 101 and a trailing(or back) surface disposed on an opposite side of the blade away fromthe direction of rotation of drill bit 101. Blades 126 may be positionedalong bit body 124 such that they have a spiral configuration relativeto rotational axis 104. In other embodiments, blades 126 may bepositioned along bit body 124 in a generally parallel configuration withrespect to each other and bit rotational axis 104.

Blades 126 may include one or more cutting elements 128 disposedoutwardly from exterior portions of each blade 126. For example, aportion of cutting element 128 may be directly or indirectly coupled toan exterior portion of blade 126 while another portion of cuttingelement 128 may be projected away from the exterior portion of blade126. Cutting elements 128 may be any suitable device configured to cutinto a formation, including but not limited to, primary cuttingelements, backup cutting elements, secondary cutting elements or anycombination thereof. By way of example and not limitation, cuttingelements 128 may be various types of cutters, compacts, buttons,inserts, and gage cutters satisfactory for use with a wide variety ofdrill bits 101.

Cutting elements 128 may include respective substrates with a layer ofhard cutting material disposed on one end of each respective substrate.The hard layer of cutting elements 128 may provide a cutting surfacethat may engage adjacent portions of a downhole formation to formwellbore 114. The contact of the cutting surface with the formation mayform a cutting zone associated with each of cutting elements 128. Theedge of the cutting surface located within the cutting zone may bereferred to as the cutting edge of a cutting element 128.

Each substrate of cutting elements 128 may have various configurationsand may be formed from tungsten carbide or other materials associatedwith forming cutting elements for rotary drill bits. Tungsten carbidesmay include, but are not limited to, monotungsten carbide (WC),ditungsten carbide (W₂C), macrocrystalline tungsten carbide and cementedor sintered tungsten carbide. Substrates may also be formed using otherhard materials, which may include various metal alloys and cements suchas metal borides, metal carbides, metal oxides and metal nitrides. Forsome applications, the hard cutting layer may be formed fromsubstantially the same materials as the substrate. In otherapplications, the hard cutting layer may be formed from differentmaterials than the substrate. Examples of materials used to form hardcutting layers may include polycrystalline diamond materials, includingsynthetic polycrystalline diamonds.

In accordance with some embodiments of the present disclosure, asdescribed below with respect to FIGS. 5 and 6, one or moreopto-analytical devices may be integrated with drill bit 101 todetermine one or more drilling characteristics associated with cuttingelements 128 including temperatures of cutting elements 128 duringdrilling, the depth of cut of cutting elements 128, wear of cuttingelements 128, the size of cuttings produced by cutting elements 128 etc.

In some embodiments, blades 126 may also include one or more depth ofcut controllers (DOCCs) 129 configured to control the depth of cut ofcutting elements 128. A DOCC 129 may include an impact arrestor, abackup cutter and/or an MDR (Modified Diamond Reinforcement). Exteriorportions of blades 126, cutting elements 128 and DOCCs 129 may formportions of the bit face.

Blades 126 may further include one or more gage pads (not expresslyshown) disposed on blades 126. A gage pad may be a gage, gage segment,or gage portion disposed on exterior portion of blade 126. Gage pads mayoften contact adjacent portions of wellbore 114 formed by drill bit 101.Exterior portions of blades 126 and/or associated gage pads may bedisposed at various angles, positive, negative, and/or parallel,relative to adjacent portions of generally vertical wellbore 114 a. Agage pad may include one or more layers of hardfacing material.

Uphole end 150 of drill bit 101 may include shank 152 with drill pipethreads 155 formed thereon. Threads 155 may be used to releasably engagedrill bit 101 with BHA 120, described in detail below, whereby drill bit101 may be rotated relative to bit rotational axis 104. Downhole end 151of drill bit 101 may include a plurality of blades 126 a-126 g withrespective junk slots or fluid flow paths 240 disposed therebetween.Additionally, drilling fluids may be communicated to one or more nozzles156. As mentioned above, in accordance with some embodiments of thepresent disclosure, one or more opto-analytical devices may beintegrated with drill bit 101 to determine the temperature of one ormore cutting elements 128 and the size of cuttings of the formation madeby cutting elements 128. Nozzles 156 may be designed based on thedetermined cutting sizes to more effectively deliver drilling fluidswhere needed. Additionally, nozzles 156 may be redesigned based on themeasured temperatures of cutting elements 128 such that nozzles 156 maymore effectively direct drilling fluid to cool cutting elements 128.

The rate of penetration (ROP) of drill bit 101 is often a function ofboth weight on bit (WOB) and revolutions per minute (RPM). Referringback to FIG. 1, drill string 103 may apply weight on drill bit 101 andmay also rotate drill bit 101 about bit rotational axis 104 to formwellbore 114 (e.g., wellbore 114 a or wellbore 114 b). The depth of cutper revolution (or “depth of cut”) may also be based on ROP and RPM of aparticular bit and indicates how deeply drill bit cutting elements 128are engaging the formation.

For some applications a downhole motor or “motor” (not expressly shown)may be provided as part of BHA 120 to also rotate drill bit 101 in orderto provide directional and horizontal drilling to form wellbore 114 bthrough kickoff location 113. There are two drilling modes duringdirectional and horizontal drilling using a motor. The first mode may bereferred to as “sliding mode” drilling. In this mode, drill string 103above the motor (not expressly shown) does not rotate in order for drillbit 101 to build/drop an angle and to drill into a curve. Sliding modedrilling may be used primarily to change drilling direction. The secondmode may be referred to as “rotating mode” drilling. In this mode, bothdrill string 103 and the motor (not expressly shown) are rotating.Rotating mode drilling may be used to drill a lateral section or astraight hole as shown in generally horizontal wellbore 114 b.

When drilling through a curved section of a wellbore in sliding mode, itmay be difficult to transfer axial force to drill bit 101 due to theaxial friction between drill string 103 and kickoff downhole wall 118 b.As the angle of wellbore 114 changes from essentially vertical toessentially horizontal through kickoff location 113, drill string 103 isheld against the lower wall of the wellbore, e.g., kickoff downhole wall118 b, by gravity. In this situation, drill string 103 from kickofflocation 113 to generally horizontal wellbore 114 b may not exert muchforce, or WOB, because most of the weight of drill string 103 is exertedon the lower wall of the wellbore. Force, or WOB, exerted on drill bit101 must overcome the friction between drill string 103 and kickoffdownhole wall 118 b of wellbore 114. This situation may lead to a smallforce, or WOB, in sliding mode in addition to a low ROP and depth of cutper revolution.

Additionally, in sliding mode drilling, torque on bit (TOB), which isthe torque used to rotate drill bit 101, may be limited because torquemay only be provided by the motor (not expressly shown) and not bydrilling rig 102. The maximum output torque from the downhole motor (notexpressly shown) may be a function of rotational speed expressed asrevolutions per minute (RPM), fluid speed expressed as gallons perminute (GPM), and operational differential pressure across the motorexpressed in pounds per square inch (psi). Accordingly, FIG. 2Billustrates graph 200 of output torque of a motor as a function ofrotational speed, fluid speed, and differential pressure. FIG. 2B may bepart of a technical specification that may be provided by a motormanufacturer. One example of a downhole motor is a SperryDrill® orGeoForce® motor (Sperry Drilling Services at Halliburton Company, TX).From FIG. 2B, for a given RPM, GPM, and differential pressure, themaximum output torque may be determined. For example, as shown by point210, at approximately 130 RPM, approximately 450 GPM, and approximately470 psi, the output torque may be approximately 4000 ft-lb for a motorhaving the characteristics illustrated in graph 200 of FIG. 2B. If TOBis larger than approximately 4000 ft-lb, then the motor may stall suchthat the motor ceases to turn. Motor stall may occur if the instantdepth of cut of drill bit 101 is large enough that the combination ofTOB and RPM produced by the motor is not sufficient to rotate drill bit101. Additionally, as the TOB increases, the drill string may experiencetorsion (e.g., twist) causing the drill string to windup. As describedin detail below with respect to FIGS. 9-10, in some embodiments one ormore opto-analytical device integrated with one or more components ofBHA 120 may be configured to measure drilling characteristics associatedwith torsion of the drill string.

Accordingly, as mentioned above and described in detail below, one ormore opto-analytical devices may be integrated with one or morecomponents of BHA 120 to determine one or more drilling characteristicsat or near the end of wellbore 114 during the process of drillingwellbore 114. The measurements obtained by the one or moreopto-analytical devices may allow for improved designs of drillingtools. The measurements of the drilling characteristics may also allowfor modifications to drilling operations during the drilling of wellbore114 to improve the efficiency of drilling wellbore 114.

Modifications, additions, or omissions may be made to FIG. 2 withoutdeparting from the scope of the present disclosure. For example, a drillbit such as drill bit 101 may be designed such that the bit does notincludes one or more blades 126. In such embodiments, cutting elements128 may be located directly on bit body 124, and may still provide acutting surface that may engage adjacent portions of a downholeformation to form wellbore 114.

FIG. 3 illustrates a block diagram of an opto-analytical device 300configured to determine one or more characteristics of a sample 304 inaccordance with some embodiments of the present disclosure. As usedherein, the term “characteristic” may refer to a chemical, mechanical orphysical property of a substance or material. A characteristic of asubstance may include a quantitative value or a concentration of one ormore chemical components therein. Illustrative characteristics of asubstance that can be monitored with the opto-analytical devicesdisclosed herein can include, for example, chemical composition of theformation (e.g. identity and concentration in total or of individualcomponents), formation fluid content (e.g., oil, gas, and/or brines),lithology of the formation (e.g. the concentration ratio of shale,sandstone, limestone and dolomite, the amount of sand, grain size in theformation, etc.), impurity content, pH, viscosity, density, strength,total dissolved solids, salt content, porosity, opacity, bacteriacontent, combinations thereof, and the like.

Opto-analytical device 300 may include an integrated computationalelement (ICE) 302 configured to receive electromagnetic radiation 301from a sample 304. ICE 302 may be configured to detect a characteristicof sample 304 based on the received electromagnetic radiation 301.

When electromagnetic radiation interacts with sample 304, uniquephysical and/or chemical information about sample 304 may be encoded inelectromagnetic radiation 301 that is reflected from, transmittedthrough or radiated from sample 304. Information associated with eachdifferent characteristic may be encoded in electromagnetic radiation301.

As used herein, the term “electromagnetic radiation” refers toelectromagnetic waves of any wavelength, including radio waves,microwave radiation, infrared and near-infrared radiation, visiblelight, ultraviolet light, X-Ray radiation and gamma ray radiation.Electromagnetic radiation 301 may come from any number of sources. Forexample, electromagnetic radiation 301 may originate from heat emanatingfrom sample 304. Electromagnetic radiation 301 may be radiationemanating from or fluorescing from sample 304. In other embodiments,electromagnetic radiation 301 may be derived from an activeelectromagnetic source (e.g., infrared, UV, visible light) thatilluminates sample 304. The electromagnetic source may be located withina portion of the drill bit, such as within a cavity of the drill bit. Insome embodiments, electromagnetic radiation may be derived from heatemanating from one or more portions of the drill bit. For example, acutting element may be formed in a way that mimics a worn cuttingelement such that it generates heat and/or electromagnetic radiationwhen it is applied to the formation. In other embodiments,electromagnetic radiation may be naturally occurring either in thebackground or from the sample itself due to natural fluorescent orphosphorescent processes. In other embodiments, electromagneticradiation may results from chemi-luminescent or tribo-luminescentprocesses. Finally, in other embodiments, electromagnetic radiation maybe obtained from optical conveying devices such as electromagneticradiation fibers, waveguides, light pipes, and the like readilyappreciated by those familiar in the art.

Sample 304 may be any type of material or area that may have one or morecharacteristics that may be of interest. For example, in the context ofdrilling, sample 304 may be the formation itself, one or more componentsof drilling tools or a space within the wellbore that may include one ormore liquids or gases, and/or the liquid or gas itself. Accordingly,electromagnetic radiation 301 received from sample 304 may includeinformation associated with any number of characteristics associatedwith sample 304. For example, if sample 304 is the formation,electromagnetic radiation 301 may include information indicating thechemical composition of the formation (e.g. identity and concentrationin total or of individual components), formation fluid content (e.g.,oil, gas, and/or brines), lithology of the formation (e.g. theconcentration ratio of shale, sandstone, limestone and dolomite, theamount of sand, grain size in the formation, etc.), impurity content,pH, viscosity, density, strength, total dissolved solids, salt content,porosity, opacity, bacteria content, combinations thereof, and the like.As another example, if sample 304 is the space within a wellbore,electromagnetic radiation 301 may include spectral signatures associatedwith the presence and/or concentration of fluids (e.g., oil or naturalgas) present in the wellbore.

ICE 302 may be configured to receive electromagnetic radiation 301 anddetect a particular characteristic of sample 304 based on a correlationassociated with the particular characteristic included inelectromagnetic radiation 301. The underlying theory behind usingintegrated computational elements for conducting analyses is describedin more detail in the following commonly owned United States Patents andPatent Application Publications, each of which is incorporated herein byreference in its entirety: U.S. Pat. Nos. 6,198,531; 6,529,276;7,123,844; 7,834,999; 7,911,605; and 7,920,258; and U.S. PatentPublication Nos. 2009/0219538; 2009/0219539; and 2009/0073433.

There are a wide variety of implementations that may be employed tocreate ICE. In one embodiment, ICE 302 may include a plurality ofalternating layers of optical elements (e.g., silicon, germanium, orother similar materials) with transmissive, reflective, and/orabsorptive properties suitable for detecting a characteristic ofinterest. For example, the alternating layers may be niobium pentoxide(Nb₂O₅), and Niobium and/or Silicon and quartz (SiO₂) deposited on asubstrate (e.g., glass, diamond, quartz, sapphire, ZnSe, ZnS, Ge, Si,etc.). In general, the materials forming the alternate layers mayconsist of materials that have indices of refraction that differ fromone another, e.g., one has a low index of refraction and the next has ahigh index of refraction. Other suitable materials for the layers mayinclude, but are not limited to, metals and their oxides andsemiconductor materials and their oxides, nitrides, and carbides such asgermanium and Germania, MgF₂, SiO, SiC, and other thin film capablematerials familiar with those skilled in the art (more complete listscan be found at: http ://www.plasmaterials.com/ThinFilmEvapMatSrcRef.pdfand http://www.cleanroom.byu.edu/TFE_materials.phtml). The number oflayers and the thickness of the layers may be determined and constructedfrom the spectral attributes of the characteristic of interest asdetermined from a spectroscopic analysis of the characteristic using aconventional spectroscopic instrument. In general, the combination oflayers correspond or are related to the spectral correlation of thecharacteristic of interest.

The multiple layers may have different refractive indices. By properlyselecting the materials of the layers and their spacing, ICE 302 can bemade to selectively transmit, absorb, and/or reflect predeterminedfractions of electromagnetic radiation at different wavelengths. Eachwavelength may be given a pre-determined weighting or loading factor.The thicknesses and spacing of the layers may be determined using avariety of approximation methods from the spectrograph of thecharacteristic of interest. These methods may include inverse Fouriertransform (IFT) of the optical transmission spectrum and structuring theoptical calculation device as the physical representation of the IFT.The approximations convert the IFT into a structure based on knownmaterials with constant refractive indices. In addition to solids, ICE302 may also contain liquids and/or gases in combination with solids tocreate the desired layers. ICE 302 may also include holographic opticalelements, gratings, and/or acousto-optic elements, for example, that maycreate the transmission, reflection, and/or absorption properties ofinterest for the layers of ICE 302.

The weightings that ICE 302 layers apply at each wavelength are set suchthat they relate or correlate to the regression weightings describedwith respect to a known equation, or data, or spectral correlation ofthe characteristic of interest. The intensity of transmitted, absorbed,or reflected electromagnetic radiation 303 is related to the amount(e.g., concentration) of the characteristic of interest associated withsample 304. Accordingly, ICE 302 may be configured to detect aparticular characteristic of sample 304 based on the correlationassociated with the particular characteristic that is included inreceived electromagnetic radiation 301.

Although the operation of ICE 302 is often illustrated in the opticaltransmission mode, it is readily understood that ICE can operate as wellin other optical modes, such as reflection, absorption, transflectance,Raman, Brillion, and Raleigh scattering modes, emittance or fluorescentmodes, as well as evanescent modes known to those skilled in the art. Inaddition, components of ICE 302 may also be realized with a variety ofother techniques. These include, but are not limited to, holographicoptical elements (HOE's), phase gratings, optical gratings, DigitalLight Pipe (DLP) devices, liquid crystal devices, photo-acousticdevices, and even naturally occurring substances such as water (e.g. ina curvette or holder) and gases (e.g. water vapor, CO, CO2, methane,hydrocarbon gases, NO and NOx nitrogen gases, etc).

In addition, significant benefits may be realized by combining theoutputs of two or more integrated computational elements with oneanother when analyzing a single characteristic of interest.Specifically, significantly increased detection accuracy may berealized. Analysis techniques utilizing combinations of two or moreintegrated computational elements are described in commonly owned U.S.patent application Ser. Nos. 13/456,255; 13/456,264; 13/456,283;13/456,302; 13/456,327; 13/456,350; 13/456,379; 13/456,405; and 13/456,443; each filed on Apr. 26, 2012 and incorporated herein by reference inits entirety.

Opto-analytical device 300 may include a detector 306 configured toreceive transmitted electromagnetic radiation 303 from ICE 302. Detector306 may include any suitable apparatus, system, or device configured todetect the intensity of transmitted electromagnetic radiation 303 andgenerate a signal related to the intensity of transmittedelectromagnetic radiation 303 received from ICE 302. For example,detector 306 may be configured to generate a voltage related to theintensity of transmitted electromagnetic radiation 303. Detector 306 maycommunicate the signal (e.g., voltage signal) related to the intensityof transmitted electromagnetic radiation 303 to a processing unit 308.Examples of detectors include split detectors, quad detectors, and arraydetectors.

Processing unit 308 may be configured to receive the signal communicatedfrom detector 306 and correlate the received signal with thecharacteristic of which ICE 302 is configured to detect. For example,ICE 302 may be configured to detect temperature of sample 304 and theintensity of transmitted electromagnetic radiation 303 transmitted fromICE 302 may accordingly be related to the temperature of sample 304.Accordingly, detector 306 may generate a voltage signal based on theintensity of electromagnetic radiation 303 and may communicate thevoltage signal to processing unit 308. Processing unit 308 may thencorrelate the received voltage signal with a temperature such thatprocessing unit 308 may determine a temperature of sample 304.

Processing unit 308 may include a processor that is any system, device,or apparatus configured to interpret and/or execute program instructionsand/or process data associated with opto-analytical device 300. Theprocessor may be, without limitation a microprocessor, microcontroller,digital signal processor (DSP), application specific integrated circuit(ASIC), or any other digital or analog circuitry configured to interpretand/or execute program instructions and/or process data. In someembodiments, the processor may interpret and/or execute programinstructions and/or process data stored in one or more computer-readablemedia included in processing unit 308.

The computer-readable media may be communicatively coupled to theprocessor and may include any system, device, or apparatus configured toretain program instructions and/or data for a period of time (e.g.,computer-readable media). The computer-readable media may include randomaccess memory (RAM), electrically erasable programmable read-only memory(EEPROM), a PCMCIA card, flash memory, magnetic storage, opto-magneticstorage, or any suitable selection and/or array of volatile ornon-volatile memory that retains data after power to processing unit 308is turned off. In accordance with some embodiments of the presentdisclosure, the computer-readable media may include instructions fordetermining one or more characteristics of sample 304 based on signalsreceived from detector 306.

ICE 302 may also be configured to reflect portions of electromagneticradiation 301 not related to the characteristic of interest as reflectedelectromagnetic radiation 305. In some embodiments, ICE 302 may reflectelectromagnetic radiation 305 toward another detector (not expresslyshown in FIG. 3). The detector configured to receive reflectedelectromagnetic radiation 305 may be configured to generate a signalassociated with reflected electromagnetic radiation 305 and communicatethe signal to processing unit 308. Processing unit 308 may use thesignal associated with electromagnetic radiation 305 to normalize thesignal associated with transmitted electromagnetic radiation 303. Inalternative embodiments, ICE 302 may be configured such that reflectedelectromagnetic radiation 305 may be related to the characteristic ofinterest and transmitted electromagnetic radiation 303 may be related toother characteristics of sample 304.

Opto-analytical device 300 may be configured to detect and determine acharacteristic of sample 304 based on electromagnetic radiation 301received from sample 304. Opto-analytical device 300 may include anynumber of ICEs 302 and associated detectors 306 configured to detect anynumber of characteristics of sample 304. Processing unit 308 mayaccordingly be configured to determine one or more properties of sample304 based on the different characteristics detected by different ICEs302 and associated detectors 306. Example characteristics that may bedetermined include chemical composition of the formation (e.g. identityand concentration in total or of individual components), formation fluidcontent (e.g., oil, gas, and/or brines), lithology of the formation(e.g. the concentration ratio of shale, sandstone, limestone anddolomite, the amount of sand, grain size in the formation, etc.),impurity content, pH, viscosity, density, strength, total dissolvedsolids, salt content, porosity, opacity, bacteria content, combinationsthereof, and the like. In some embodiments, the characteristicsdescribed above directly correlate to the signal of the opto-analyticaldevice and no further analysis is required to obtain the characteristicof interest. In other embodiments, processing unit 308 may determineother physical properties of the formation such as rock strength,porosity, density, or any other characteristic based upon the detectedchemical compositions or characteristics of interest. Additionally, insome embodiments processing unit 308 may be configured to storecollected data associated with a detected characteristic in any suitablestorage medium. The collected data may then be retrieved at a later timeand may be analyzed and processed to determine various properties ofsample 304. In embodiments where opto-analytical device 300 isintegrated with a drilling tool, processing unit 308 may be configuredto communicate information associated with a detected characteristic toa well site using any suitable measurement while drilling (MWD)communication system.

When monitoring more than one characteristic at a time, variousconfigurations for multiple ICEs 302 may be used, where each ICE 302 hasbeen configured to detect a particular characteristic of interest. Insome embodiments, the characteristic may be analyzed sequentially usingmultiple ICEs 302 that are presented to a single beam of electromagneticradiation being reflected from or transmitted through a sample. In someembodiments, multiple ICEs can be located on a rotating disc, where theindividual ICEs are exposed to the beam of electromagnetic radiation fora short period of time. Advantages of this approach may include theability to analyze multiple characteristics using a single opticalcomputing device and the opportunity to assay additional characteristicssimply by adding additional ICEs to the rotating disc. In variousembodiments, the rotating disc can be turned at a frequency of about 1RPM to about 30,000 RPM such that each characteristic in a sample ismeasured rapidly. In some embodiments, these values may be averaged overan appropriate time domain (e.g., about 1 millisecond to about 1 hour)to more accurately determine the sample characteristics.

In other embodiments, multiple ICEs 302 may be placed in parallel, whereeach ICE 302 is configured to detect a particular characteristic ofinterest. In such embodiments, a beam splitter may divert a portion ofthe electromagnetic radiation from the substance being analyzed to eachICE 302. Each ICE 302, in turn, may be communicatively coupled todetector 306 or array of detectors 306 configured to detect an output ofelectromagnetic radiation from the ICE 302. Parallel configurations ofICEs 302 may be particularly beneficial for applications that requirelow power inputs and/or no moving parts. Parallel configurations ofICE's may also be particularly beneficial for applications where changesin characteristic values are rapid, such as high velocity flows.

In still additional embodiments, multiple ICEs 302 may be placed inseries, such that characteristics are measured sequentially at differentlocations and times. For example, in some embodiments, a characteristiccan be measured in a first location using a first ICE 302, and thecharacteristic can be measured in a second location using a second ICE302. In other embodiments, a first characteristic may be measured in afirst location using a first ICE 302, and a second characteristic may bemeasured in a second location using a second ICE 302.

Any of the foregoing configurations for the optical computing devicesmay be used in combination with a series configuration in any of thepresent embodiments. For example, two rotating discs having a pluralityof ICEs may be placed in series for performing an analysis. Likewise,multiple detection stations, each containing ICEs 302 in parallel, maybe placed in series for performing an analysis.

As mentioned above, an opto-analytical device 300 integrated with adrilling tool, such as drill bit 101 may be used to detect any number ofcharacteristics associated with drilling a wellbore in a formation, suchas chemical composition of the formation (e.g. identity andconcentration in total or of individual components), formation fluidcontent (e.g., oil, gas, and/or brines), lithology of the formation(e.g. the concentration ratio of shale, sandstone, limestone anddolomite, the amount of sand, grain size in the formation, etc.),impurity content, pH, viscosity, density, ionic strength, totaldissolved solids, salt content, porosity, opacity, bacteria content,combinations thereof, or the like. The detection of characteristics mayalso be used to determine an event associated with drilling a wellbore.In some embodiments, drilling of a wellbore may be modified based on thedetected characteristic.

For example, opto-analytical device 300 may be configured to detect theconcentration of certain gases in a wellbore (e.g., wellbore 114 asillustrated in FIG. 1). Accordingly, when a change in gas concentrationoccurs, opto-analytical device 300 may detect change and drilling may beadjusted accordingly. As an example, opto-analytical device 300 may beconfigured to detect changes in the concentration of natural gas. Asharp increase in natural gas concentrations may indicate that thewellbore has reached a natural gas reservoir. Drilling may then bemodified based on reaching the natural gas reservoir. For example,weight may be taken off the drill bit and a seal may be placed againstthe wall of the wellbore to seal the gas in the reservoir. In someembodiments, the sealing may be done at a BHA (e.g., BHA 120 asillustrated in FIG. 1) by processing unit 308 communicating a controlsignal to expand a donut to seal the gas in the wellbore upon detectingthe gas. For example, when the detected event is transmitted to thesurface, drilling fluid flow rates may be increased and the drillingfluid density may be optimized to maintain a pressure at the surfacehigher than the formation pressure in order to maintain control of thewell. The drilling fluid chemistry may also be changed to includematerials designed to ameliorate the toxic effects the gas. Other eventsthat may be detected using an opto-analytical device 300 may be a changein the chemistry, rock strength, porosity and/or density of theformation being drilled. The chemistry change may indicate that adifferent type of rock is being drilled into, which may have differentphysical properties (e.g., hardness, plasticity, permeability, porosity,etc.). Drilling may be modified accordingly (e.g., the RPM, WOB etc. maybe increased or decreased depending on the change in the formation). Forexample, if the formation is hard and the rock strength is high, a newdrill bit with high density of cutting elements and small size ofcutting elements may be used. If the formation is very plastic, a newshape of cutting elements such as scribe cutters may be used. If thereis a change from a hard dolomitic limestone to a shale, one or morechanges in drilling (e.g., introduction of drilling fluid to prevent theshale from hydrating, a reduction in the WOB or an increase in thelubrication of the drilling fluid) may be made. In some high pressureand high temperature cases, a roller cone bit may be used instead of aPDC bit. As another example, the detection of a change from a harddolomitic lime stone to a shale may call for multiple changes in thedrilling operation, such as drilling fluid to prevent the shale formhydrating, a reduction in the weight on bit, or an increase in thedrilling fluid system's lubricity. Normally, these changes that would bemade by an observer present at the bit. However, these changes wouldonly be observed after the drilling fluid has carried the cutting tosurface, a lag time in which the drilling fluid bit interaction is lessthan optimum and potentially damaging to the well. According toembodiments of the present disclosure, however, these changes may bemade at a faster rate based upon events detected by the opto-analyticaldevice.

Another event that an opto-analytical device 300 may detect is a changein from one material state (e.g., solid, liquid, gas) to another. Suchchanges may indicate, for example, the entrance or exit of the drillingtool with respect to a hollow pocket in the formation. As anotherexample, such changes may indicate that the drilling tool hasencountered or exited oil or gas reservoirs. For instance, anopto-analytical device 300 embodied in a horizontal strata reservoir mayanalyze material state to detect a water/oil interface and ensure thewellbore is above the water/oil interface. In addition, theopto-analytical device 300 may detect whether the bit has exited acertain zone of interest based on changes in material states. In theevent of a detected change of material state, one or more modificationsmay be made to the drilling, such as lowering or increasing an RPM orchanging the direction of the drilling. Furthermore, because the fluidflow and pressure balance at the surface of the formation is a criticalprocess in drilling, uncontrolled flow into the formation (sometimesreferred to as “blow out”) can destroy the formation and may stopdrilling until the fluid loss is controlled. Thus, in some embodiments,an opto-analytical device may detect the flow of reservoir fluids intothe well bore, separate from the fluids that were in the rock freshlydrilled by the bit. Certain modifications may then be made to thedrilling procedure based on the detected flow. For example, finepressure control may be achieved by increasing the drilling fluid flowrate, which may increase the local pressure at the surface throughdynamic forces (e.g., viscosity of the drilling fluid). This may helpdisperse the incoming formation fluid while the drilling fluid systembulk density is changed at surface and circulated into the hole.Normally, this process has a lag time. However, certain embodiments ofthe present disclosure may correct this using downhole detection offluids entering the well bore. For instance, the amount of water in thedrilling fluid system may be modified in order to stabilize theformation based on washouts of materials such as clay or shale lensescan be detected.

An opto-analytical device 300 may also be configured to detect pH of adownhole fluid sample and thus changes in pH. The changes in pH mayindicate whether the downhole fluid sample is from drilling fluids oranother fluid present in the wellbore (e.g., oil, or water). A change inpH may also indicate, for example, where a fluid of interest (or itssource) is located in the formation. As an example, two sources of watermay be encountered: salt or fresh water. The pH would be different foreach case, thereby enabling an operator of the drilling tool todetermine the source of the fluid (and thereby enable the user toameliorate or enhance its influence, depending upon the desirability.)Depending upon what fluid is encountered, a user may want to not onlychange a drilling speed, for example, but also a drilling direction. Asanother example, in the event of formation water entering the well bore(which is usually low pH due to the dissolution of acid gases in thewater (predominantly carbon dioxide and hydrogen sulfide)), the drillingfluid system may be modified to maintain at least a neutral to high pH.

In the same or alternative embodiments, opto-analytical device 300 maybe configured to determine a change in total dissolved solids within adrilling fluid. Examples may include dissolved rocks or rock saltdissolved in the fluid. This information may indicate what material isbeing encountered in the formation or the chemical or physicalcomposition of the formation. Based on this information, a user may wantto make drilling modifications. For instance, if a salt dome isencountered, the operator may want to change drilling parameters, suchas RPM, WOB, or drilling direction.

Additionally, opto-analytical device 300 may be configured to determineresidual stress of a formation. Residual stress may indicate thelocation of where the formation may fracture, and may be determinedbased on the gauge of the wellbore, as measured by the opto-analyticaldevice, shortly after the drill bit has passed. Based on the determinedresidual stress, one or more modifications may be made to the drilling.For example, an operator may change the direction of drilling in orderto avoid locations where the formation may fracture. As another example,the drilling may be stopped after determining a certain level ofresidual stress in order to avoid potential explosive, toxic, orcorrosive gases and/or chemicals. Additionally, the stress state of theformation may inform the decision to case the well and to control therisk in the casing operation. For instance, long open hole sectionsunder high stress conditions may collapse or may cause a casing to stickin the wellbore as the shape of the wellbore gradually oblates (i.e.,changes from circular to elliptical). The casing installation may bedelayed by such sticking and geometric locking, sometimes resulting inthe abandonment of a section of the well or a sidetrack drillingoperation, leading to great economic consequences.

The above is merely a list of examples of events associated withdrilling a wellbore that may be detected by an opto-analytical device300. Additionally, the modifications to drilling listed are merelylisted as examples. Any number of drilling modifications may be madebased on events detected or measurements performed by one or moreopto-analytical devices 300.

One or more opto-analytical devices, such as opto-analytical device 300,may be integrated with one or more drilling tools of a bottom holeassembly such as BHA 120 of FIG. 1. FIG. 4 illustrates a cross-sectionalview of an example configuration of drill bit 101 having opto-analyticaldevice 300 integrated therein. Drill bit 101 of FIG. 4 may include acavity 408 formed in bit body 124 and configured to houseopto-analytical device 300 described in detail above with respect toFIG. 3. Cavity 408 may also include power source 404 configured toprovide power to one or more components of opto-analytical device 300.For example, in some embodiments, power source 404 may be any suitabletype of battery. Power source 404 may also be a piezoelectric deviceconfigured to generate electricity based on the movement and vibrationof drill bit 101 during a drilling process. Although shown as havingonly one power source 404, cavity 404 may include any number of powersources 404 used in any suitable combination. For example, in someembodiments cavity 408 may include a battery power source and apiezoelectric power source. In the same or alternative embodiments, thepiezoelectric power source may be configured as a primary power sourcewhen drill bit 101 is moving and the battery power source may beconfigured as a backup power source when drill bit 101 is not moving.Additionally, in some embodiments, the piezoelectric power source may beconfigured to charge the battery power source. Other power sources mayinclude generators, or micro-generators deriving their power from themovement (or differential movement) of the bit itself, or the movementof the fluids, chemical batteries, solar power sources (which wouldderive their power from the infrared/visible electromagnetic radiationgenerated by the drill bits themselves), or nuclear sources.

Cavity 408 may also be configured to house electromagnetic radiationsource 406. Electromagnetic radiation source 406 may include anysuitable apparatus, system, or device configured to generateelectromagnetic radiation in a desired spectrum. For example, anelectromagnetic radiation source 406 may be configured to generateinfrared light, visible light, UV light, X-rays etc. As explainedfurther below, the electromagnetic radiation from electromagneticradiation source 406 may be directed toward a sample (e.g., formation,wellbore, drilling tool component, etc) such that the electromagneticradiation from electromagnetic radiation source 406 impinges the sample.The electromagnetic radiation may then be transmitted, reflected,refracted, absorbed, etc. by the sample and received by opto-analyticaldevice 300 to determine one or more characteristics of the sample.Electromagnetic radiation source 406 may be configured to receive powerfrom power source 404.

Cavity 408 may also be coupled to one or more channels 402 configured todirect electromagnetic radiation to opto-analytical device 300 or fromelectromagnetic radiation source 406. Channels 402 may be formed in anysuitable location of drill bit 101 to direct electromagnetic radiationto or from any desired location on drill bit 101. In the illustratedembodiment, channels 402 are formed in a blade 126 to directelectromagnetic radiation to or from different locations on blade 126.For example, channel 402 a is configured to direct electromagneticradiation to or from the face of cutting element 128, channel 402 b isconfigured to direct electromagnetic radiation to or from DOCC 129,channel 402 c is configured to direct electromagnetic radiation to orfrom a gage portion of blade 126 and channel 402 d is configured todirect electromagnetic radiation to or from a location on a side face ofblade 126. The actual locations of channels 402 may vary according tothe desired location of illumination of an area with electromagneticradiation or a desired area for receiving electromagnetic radiation foranalysis by an opto-analytical device 300.

Channels 402 may be configured to direct electromagnetic radiation usingany suitable method, system, or device. For example, one or morechannels 402 may be filled with an optically transmissive material suchas diamond or sapphire that may direct electromagnetic radiation throughchannels 402. As another example, one or more channels 402 may be coatedwith a reflective material such as aluminum that may directelectromagnetic radiation through channels 402. Additionally, one ormore channels 402 may include an optical fiber, waveguide, or light pipeconfigured to carry and direct electromagnetic radiation. In someembodiments, the end of channels 402 opposite of cavity 408 may includewindows 401 configured to prevent materials from entering the channels402. Windows 401 may be any optically transmissive material suitable forwithstanding drilling conditions, such as diamond, sapphire, zincsulfide and zinc sulfide coated zinc selenide.

In some embodiments, channels 402 may be configured to house one or morecomponents of opto-analytical device 300. For example, ICE 302(described in FIG. 3) may be included in one or more channels 402 behindwindows 401 such that the ICE 302 may receive electromagnetic radiationat or near windows 401. Additionally, detector 306 (described in FIG. 3)may be placed behind ICE 302 in channels 402. In the same or alternativeembodiments, a plurality of ICEs 302 may be placed in series with eachother in one or more channels 402.

Accordingly, in accordance with the present disclosure, through the useof windows 401, channels 402 and cavity 408, drill bit 101 may beconfigured to have one or more opto-analytical devices 300, powersources 404 and electromagnetic radiation sources 406 integratedtherein. Therefore, drill bit 101 may be configured to directelectromagnetic radiation to and from desired locations such that theone or more opto-analytical devices 300 may analyze and detect one ormore drilling characteristics.

Modifications, additions, or omissions may be made to FIG. 4 withoutdeparting from the scope of the present disclosure. For example, thesame principles described with respect to integrating opto-analyticaldevice 300 with drill bit 101 may be used to integrate opto-analyticaldevice 300 with any other drilling tool (e.g., a reamer, a stabilizer,etc.). Additionally, the locations and configurations of windows 401,channels 402, cavity 408, power source 404, electromagnetic radiationsource 406 and opto-analytical device 300 are merely shown as aconceptual embodiment and the actual configuration may vary depending onthe particular application. It will be understood by those of ordinaryskill in the art that the illustrative examples and embodimentsdescribed herein for transmission modes (i.e. directing electromagneticradiation toward a sample) would equally apply to absorptive orreflective implementations, and vice-versa.

One or more opto-analytical devices 300 may be configured to determineany number of performance indicators of a drilling tool. For example,one or more opto-analytical devices 300 may be configured to determinethe size and quantity of cuttings created by cutting elements 128cutting into a formation. In some embodiments, certain characteristicsof the cuttings (e.g., size and/or number) may indicate the cuttingefficiency of a drill bit. As such, it may be advantageous to monitorthe cuttings in flow channels of the drill bit to determine if the drillbit is efficiently cutting into the formation. FIG. 5 illustrates anexample embodiment of drill bit 101 including one or moreopto-analytical devices (not shown) configured to determine the size ofcuttings 502 created by cutting elements 128, in accordance with someembodiments of the present disclosure. The one or more opto-analyticaldevices may be located in any suitable location of drill bit 101 todetermine the size of cuttings 502. For example, the opto-analyticaldevice may be located in channels of drill bit 101, in windows 401 ofdrill bit, on one or more cutting elements 128 of drill bit 101, on oneor more DOCCs 129 of drill bit 101, on one or more blades 126 of drillbit 101, in one or more nozzles 156 of drill bit 101, in fluid flowpaths 240 of drill bit 101, on shank 152 of drill bit 101, or any othersimilar location for determining the size of cuttings 502. In someembodiments, a processing unit 308 of opto-analytical device 300 may beconfigured to determine and store the size or other characteristic(s) ofcuttings 502 as a function of time in a computer-readable medium toallow for retrieval of the data at a later time. In the same oralternative embodiments, the processing unit 308 may be configured totransmit the size determinations during drilling operations via anysuitable MWD system.

In the illustrated embodiment, the leading face of blade 126 g mayinclude an electromagnetic radiation source (not expressly shown) andchannel (not expressly shown) configured to direct electromagneticradiation through window 401 a of drill bit 101. In some embodiments,the electromagnetic radiation source may be configured to generatevisible light and may include an incandescent light source (e.g.tungsten), a light emitting diode (LED), a laser, a fluorescent and/orphosphorescent light source, a tribo-luminescent source, or any othersuitable electromagnetic radiation source.

The electromagnetic radiation transmitted from window 401 a mayilluminate cuttings 502 that move through a flow channel of drill bit101 and past window 401 a. Cuttings 502 may be pieces of a rockformation that are cut away by cutting elements 128. In someembodiments, cuttings 502 may be directed past through the flow channeland window 401 a by drilling fluid flowing out of a nozzle 156. When theelectromagnetic radiation impinges cuttings 502, cuttings 502 mayreflect the electromagnetic radiation. Window 401 b of blade 126 g maybe configured to receive the electromagnetic radiation reflected bycuttings 502. Window 401 b may also be configured to direct thereflected electromagnetic radiation toward opto-analytical device 300 inchannel 402 (described in FIGS. 3 and 4, and not expressly shown in FIG.5). Although not expressly shown, in some embodiments of drill bit 101each blade 12 may include window 401 a configured to directelectromagnetic radiation from an electromagnetic radiation source ontocuttings 502. Additionally, although not expressly shown each blade 126may include window 401 b configured to receive electromagnetic radiationreflected by cuttings 502.

Opto-analytical device 300 may be configured to detect the size ofcuttings 502 based on the intensity of the electromagnetic radiationreceived by opto-analytical device 300 because electromagnetic radiationtransmitted, reflected, or absorbed by the cuttings is correlated and/orrelated to the size and distribution of the cuttings. In someembodiments, opto-analytical device 300 may be configured to detect anddetermine an approximation of the maximum and/or minimum size ofcuttings 502. The sizes of the cuttings 502 may indicate the efficacy ofcutting elements 128. For example, if the sizes of cuttings 502decrease, this may indicate that one or more cutting elements 128 arebeing worn and/or that cutting elements 128 have transitioned intocutting into a harder rock. Conversely, if the sizes of cuttings 502increase, this may indicate that cutting elements 128 have transitionedinto cutting into a softer rock.

In addition to determining the size of cuttings 502, opto-analyticaldevice 300 may be configured to determine other characteristics ofcuttings 502 such as their chemical composition, hardness, etc. Thechemical composition, hardness, etc. of the cuttings 502 may be comparedwith the sizes of the cuttings 502 to help better correlate the efficacyof cutting elements 128 with respect to different rock types.Accordingly, opto-analytical device 300 may measure and collect datathat may be helpful in designing cutting elements for differentformations having different properties (e.g., rock strength, stress,porosity, density, plasticity, rock type, rock composition, etc.).

Additionally, the efficacy and wear of cutting elements 128 (and thusthe associated sizes of cuttings 502) may be based on the amount ofdrilling fluid moving past cutting elements 128. For example, thedrilling fluid may cool cutting elements 128 to prolong the life ofcutting elements 128. Additionally, the drilling fluid may help movecuttings 502 away from cutting elements 128 to allow cutting elements128 to more effectively cut into the formation. The sizes of cuttings502 may therefore indicate how much drilling fluid is reaching cuttingelements 128. For example, the size of cuttings 502 measured by oneopto-analytical device 300 on drill bit 101 may be substantially smallerthan the size of cuttings 502 measured by another opto-analytical device300 on drill bit 101, indicating that the cutting elements 128associated with the smaller cuttings 502 may not be receiving asufficient amount of drilling fluid. Therefore, the design of drill bit101, including the number, size, and/or orientation of nozzles 156, maybe modified to better deliver drilling fluid to those cutting elements128.

One or more opto-analytical devices 300 may also be configured todetermine the concentration of cuttings 502 in the drilling fluid movingpast window 401 b based on the size and distribution of the cuttings.The concentration of cuttings 502 may indicate the efficacy of cuttingelements 128 where a higher concentration of cuttings 502 may indicate ahigher cutting efficiency and a lower concentration of cuttings mayindicate a lower efficiency of cutting elements 128. Additionally, ahigher concentration of cuttings 502 may indicate a higher rate ofpenetration than a lower concentration of cuttings 502. Furthermore, aconcentration of cuttings 502 as measured by one of opto-analyticaldevices 300 that is lower than the concentration of cuttings 502measured by another opto-analytical device 300 on drill bit 101 mayindicate that cutting elements 128 on different areas of drill bit 101are cutting into the formation at different depths. Also, theconcentration of cuttings 502 in drilling fluid may indicate theefficacy of nozzles 156 in delivering drilling fluid to cutting elements128 to carry cuttings 502 away from cutting elements 128. One or morecutting elements 128 and/or nozzles 156 may accordingly be designedbased on the cuttings concentration measurements to improve the flow offluid past cutting elements 128 and/or the efficacy of cutting elements128.

One of skill in the art will appreciate that one or more characteristicsof cuttings 502 may be determined at any location in the wellbore. Forinstance, one or more characteristics of cuttings 502 may be determinedfurther uphole than drill bit 101. For example, by measuring the size ofcuttings 502 both at drill bit 101 and further uphole, it may bedetermined that the size of cuttings 502 is changing as they are removedfrom wellbore 114. An increase in the size cuttings 502, for example,may indicate that cuttings 502 have expanded in the drilling fluid.Accordingly, the amount or composition of the drilling fluid may bealtered to avoid cuttings 502 from increasing or decreasing in size asthey are removed from wellbore 114.

Therefore, one or more opto-analytical devices 300 may be configured todetermine one or more characteristics of cuttings 502 such as the size,porosity, composition, and/or the amount or concentration of cuttings502. The characteristics of cuttings 502 may indicate the efficacy ofone or more components of a drilling tool, such as cutting elements 128and nozzles 156, as well as the performance of the drilling tool itself(e.g., the rate of penetration of the drilling tool). The size ofcuttings may be directly related to the depth of cut per revolution ofcutting elements (which is a function of bit rotational speed and ROP orWOB). Therefore, for a given drill bit, the size of cuttings mayindicate whether an applied WOB and/or bit rotational speed leads toefficient drilling. Accordingly, any suitable change, including themodification of the WOB, RPM, or direction or orientation of the drillbit, may be made as necessary or dictated by the determinedcharacteristics. In addition, control and modulation of the fluidthrough individual jets may be accomplished based on the determinedcuttings sizes, which is very desirable. The drilling fluid through eachnozzle 156 may modulated to optimize rate of penetration by keepingindividual cutters cool, transporting cuttings, and hydraulicallyjet-drilling softer formations. Taken to an extreme, the modulated flowcan cause cavitation at the rock surface, causing the rock to fail andallowing spoil to be transported uphole.

Modifications, additions, or omissions may be made to FIG. 5 withoutdeparting from the scope of the present disclosure. For example, aroller cone drill bit, a reamer or any other drilling tool may besimilarly configured to detect one or more characteristics of cuttings502. Additionally, the locations of windows 401 and the particularelectromagnetic radiation source may vary depending on the application.

FIG. 6 illustrates an example method 600 for analyzing cuttingsassociated with drilling a wellbore, in accordance with some embodimentsof the present disclosure. Method 600 may be performed by any suitablesystem, apparatus, or device. In the present example, method 600 may beperformed using a drill bit 101 configured as described with respect toFIG. 5. However, method 600 may be performed using any suitable drillingtool configured to analyze cuttings created by the drilling tool.

Method 600 may start and at step 602 drill bit 101 may be used to drilla wellbore by cutting into a geological formation. At step 604, anelectromagnetic radiation source, located in a first channel formed indrill bit 101 may direct electromagnetic radiation through a firstwindow and toward cuttings created by drill bit 101 cutting into aformation. The window and channel may be located at any suitablelocation on drill bit 101. At step 606, opto-analytical device 300 ofdrill bit 101 may detect electromagnetic radiation from theelectromagnetic radiation source that reflects off of the cuttings. Theelectromagnetic radiation may be directed to opto-analytical device 300via the first window and first channel, where opto-analytical device 300is located. Alternatively, as described with respect to FIG. 5, theelectromagnetic radiation may be directed to opto-analytical device 300via a second window and a second channel, where opto-analytical device300 is located. In one embodiment, the second window may be located on asecond blade opposite of the first window, as shown in FIG. 5. Inanother embodiment, the second window may be located on the same bladeas the first window where opto-analytical device 300 is located.

At step 608, opto-analytical device 300 may detect and determine one ormore characteristics of cuttings 502 based on the electromagneticradiation received from the cuttings. As described above with respect toFIG. 5, example characteristics of cuttings 502 that may be detected anddetermined are the size, porosity, composition, and/or the amount orconcentration of cuttings 502, or any combination thereof. Thesecharacteristics may be used to determine the amount of desirable and/orundesirable materials inside the formation.

At step 610, the characteristics associated with the cuttings may beanalyzed. For example, the sizes, shapes, and/or concentrations ofcuttings as measured by different opto-analytical devices 300 located atdifferent areas of drill bit 101 may be analyzed to compare the cuttingefficiency of cutting elements 128 at different locations of drill bit101. Additionally, the sizes and/or concentrations of the cuttings maybe compared with the chemical composition of the cuttings to determinecutting efficiency for different formation types. Further, the sizes,shapes, and/or concentrations of the cuttings may be analyzed todetermine the efficacy of nozzles 156 in delivering drilling fluid tocutting elements 128. The sizes, shapes, and/or concentrations of thecuttings may also be used to determine the effectiveness of the drillingfluid such as drilling fluid density and drilling fluid capacity. Inaddition, the cutting characteristics may also indicate a certaindrilling direction or bit orientation.

At step 612, one or more parameters of drill bit 101 may be modifiedbased on the analysis of the cuttings. For example, the sizes and/orconcentrations of cuttings at different locations of drill bit 101 mayindicate uneven cutting by cutting elements 128 and/or fluiddistribution by nozzles 156. Accordingly, the placement, size, and/orconfiguration of one or more nozzles 156 and/or cutting elements 128 maybe modified to achieve more even cutting and/or fluid distribution.Further, the sizes and/or concentrations of the cuttings with respect tothe composition of the cuttings may indicate the efficacy of cuttingelements 128 with respect to formations having that particularcomposition. Accordingly, determinations may be made regarding whetheror not the design of cutting elements 128 may be modified to improvecutting into formations having similar compositions. For example, if theequivalent circulating density (ECD) of the drilling fluid becomes toohigh, the formation could be damaged. Accordingly, decreasing the ROP byreducing the WOB or RPM may result in a lower rate of cuttings enteringthe fluid flow and may reduce the equivalent density of the drillingfluid. For example, the size of cuttings for a given formation may bedirectly related to the density of cutting elements on the bit face. Thesmall size of the cuttings may indicate that the cutting elements grindthe formation with low cutting efficiency. In this case, the number ofblades and the number of cutting elements on the drill bit may bereduced. As another example, the drilling direction or bit orientationmay be altered based on the determined cuttings characteristics.

Another performance indicator of a drilling tool that may be measured byopto-analytical device 300 may be the temperature of one or more cuttingelements 128. In some embodiments, an increase in temperature of acutting element may indicate an increased force on the drill bit and/orsignificant wear of the cutting element. As such, it may be advantageousto monitor the temperature of one or more cutting elements on the drillbit to determine if there is increased force on the drill bit orexcessive wear of the cutting elements in order to modify the drillingconditions. FIG. 7A illustrates an example embodiment of temperaturesensor 700 including opto-analytical device 300 configured to measurethe temperature of cutting element 128 of drill bit 101. Temperaturesensor 700 may include channel 702 (similar to channels 402 describedwith respect to FIG. 4) formed in cutting element 128 and blade 126. Inthe illustrated embodiment, channel 702 may be behind face 704 ofcutting element 128. Channel 702 may be configured to direct infraredelectromagnetic radiation to opto-analytical device 300 including ICE302 (as illustrated in FIG. 3, and not expressly shown in FIG. 7A)configured to detect temperature based on a spectral signatureassociated with temperature. FIG. 7B illustrates example spectralsignatures 706 and 708 of a material for temperatures of approximately900 degrees and 700 degrees, respectively. The y-axis shown is thespectral radiant density with units of W/(nm*m̂2) and the x-axis shown isthe wavelength with unit of nm. In some embodiments, a processing unitof an opto-analytical device (e.g., opto-analytical device illustratedin FIG. 3) of temperature sensor 700 may be configured to determine andstore the temperature as a function of time in a computer-readablemedium to allow for retrieval of the data at a later time. In the sameor alternative embodiments, the processing unit 308 may be configured totransmit the temperature measurements during drilling operations via anysuitable MWD system.

The amount of wear of cutting elements 128 may be based on a variety offactors including cutting force, cutting speed and cutting elementtemperature. Additionally, as cutting element 128 wears, it may be lesseffective at cutting into a formation such that the temperature of thecutting element 128 may increase. Further, as drilling conditions change(e.g., the formation changes), the efficacy of cutting element 128 mayalso change such that the temperature of the cutting element 128changes. Accordingly, temperature sensor 700 may be used to determineany number of drilling characteristics based on the temperature of oneor more cutting elements 128. Additionally, processing the signal oftemperature sensor 700 may yield an acoustic signature of a formation,which may be used in determining a formation type and/or wear conditionsof cutting elements 128.

FIG. 7C illustrates an example configuration of temperature sensors 700integrated with cutting elements 128 and configured to indicate one ormore drilling characteristics based on the temperature of cuttingelements 128. In the illustrated embodiment cutting element 128 b, whichis on a cone portion of blade 126 of drill bit 101, may include atemperature sensor 700 a integrated therein, such as shown with respectto FIG. 7A. Cutting element 128 d, which is located within a noseportion of blade 126, may include temperature sensor 700 b integratedtherein. Temperature sensors 700 a and 700 b may be configured tomeasure the temperatures of cutting elements 128 b and 128 d,respectively. In some embodiments, temperature sensors 700 a and 700 bmay be configured to store the temperatures as a function of time in acomputer-readable medium, such that the measurements may be retrieved ata later time. In other embodiments, the measurements may be communicatedto the well site using any suitable MWD system.

The temperature measurements of cutting elements 128 b and 128 d overtime may indicate one or more drilling characteristics. FIG. 7Dillustrates example plots 710 and 712 of the temperatures of cuttingelements 128 b and 128 d as a function of time, according to someembodiments of the present disclosure. Both plots 710 and 712 show arelatively rapid increase in temperature at time t₁. In many drillingcases, cutting elements located on the cone portion of a blade (e.g.,cutting element 128 b) may experience little wear. Therefore, arelatively rapid increase in temperature of cutting element 128 b attime t₁ may indicate that a drilling condition has changed (e.g., theformation hardness has increased). Additionally, the increase intemperature at time t₁ of both cutting elements 128 b and 128 d mayindicate that the increase in temperature may be caused by a change indrilling conditions.

However, plot 712 shows an increase in temperature of cutting element128 d at time t₂ while plot 710 does not show an increase in temperatureof cutting element 128 b at time t₂. Therefore, the temperature increaseat time t₂ in plot 712 may indicate wear of cutting element 128 d (andperhaps cutting elements 128 located near cutting element 128 d).Similarly, the lack of a substantial temperature increase of cuttingelement 128 b at time t₂ in plot 710 may indicate little to no wear ofcutting element 128 b (and perhaps cutting elements 128 near cuttingelement 128 b). Therefore, one or more temperature sensors 700 thatinclude opto-analytical device 300 may be integrated with a drill bit todetect one or more drilling characteristics such as cutting elementwear, drilling condition changes, etc.

Based on a comparison of the temperatures of cutting elements 128 b and128 d, one or more drilling factors may be modified. In someembodiments, WOB may be modified based on the comparison. For example,if the temperature of a particular cutting element increasessignificantly, this cutting element may be subjected too much force.Thus, WOB may be lowered in such a condition. As another example, if thetemperature of one or more cutting elements in a nose zone of the drillbit increases, but the temperature of the cutting elements in the conezone of the drill bit remains the same or does not increasesignificantly, cutting elements in the nose zone may be subjected to toomuch wear. Accordingly, the amount of drilling fluid may be modifiedbased on the comparison. For example, a high temperature at both cuttingelements may indicate the need for additional drilling fluid forlubricant. Accordingly, more drilling fluid may be added. As anotherexample, drilling may be slowed or stopped if high bit temperatures aresensed in order to avoid certain types of gases escaping to the surfaceof the drilling site. As yet another example, drilling may be stopped inorder to service or otherwise perform maintenance on the drill bit.

Modifications, additions, or omissions may be made to FIGS. 7A-7Dwithout departing from the scope of the present disclosure. For example,the particular placement and configuration of temperature sensors 700depicted in FIGS. 7A-7D is for illustrative purposes only. Theplacement, number, and configuration of temperature sensors 700 may varydepending on the application. Additionally, temperature sensor 700 maybe used to determine the temperature of any number of objects associatedwith drilling (e.g., the formation, the drilling fluid, other componentsof a drill bit, drilling tool or the drill string) and is not limited todetermining the temperature of a cutting element 128. Furthermore,opto-analytical device 300 of temperature sensor 700 may be configuredto detect any number of other drilling characteristics (e.g., chemicalcomposition of the formation (e.g. identity and concentration in totalor of individual components), formation fluid content (e.g., oil, gas,and/or brines), lithology of the formation (e.g. the concentration ratioof shale, sandstone, limestone and dolomite, the amount of sand, grainsize in the formation, etc.), impurity content, pH, viscosity, density,strength, total dissolved solids, salt content, porosity, opacity,bacteria content, combinations thereof, and the like) while alsodetermining temperature measurements.

FIG. 8 illustrates an example method 800 for determining one or moredrilling characteristics based on temperature, in accordance with someembodiments of the present disclosure. Method 800 may be performed byany suitable system, apparatus, or device. In the illustratedembodiment, method 800 may be performed using a drill bit 101 configuredwith a temperature sensor 700 as described with respect to FIGS. 7A-7D.However, method 800 may be performed using any suitable drilling toolconfigured to analyze cuttings created by the drilling tool.

Method 800 may start and at step 802 drill bit 101 may form a wellboreby drilling into a geological formation. At step 804, electromagneticradiation associated with heat of a cutting element 128 may be receivedby channel 702 associated with a temperature sensor 700, as describedabove with respect to FIG. 7A. At step 806, temperature sensor 700 maydetect and determine the temperature of the cutting element 128 using anopto-analytical device 300 included in temperature sensor 700, asdescribed above with respect to FIGS. 7A-7D. In some embodiments,temperature sensor 700 may be configured to store the temperature of thecutting element 128 as a function of time in a computer readable medium,or may be configured to transmit the temperature of the cutting element128 as a function of time uphole via a MWD system.

At step 808, temperature sensor 700 determines whether there has been achange in temperature. If a temperature change has been detected at step808, the method moves to step 810, where one or more drilling parametersmay be modified based on the detected change in temperature. Forinstance, if a temperature increase is detected, it may indicate thatthe input mechanical energy to the bit is too high and either RPM or WOBmay be reduced. A higher temperature associated with cutting elementsmay also indicate that the cuttings created on bottom may not beproperly cleared and drilling fluid density and/or speed at whichdrilling fluid is introduced may be adjusted. If drilling in a highpressure and high temperature formation, measurement of temperaturebecomes even more important. As another example, a change in temperaturemay indicate a transition from one formation type to another, which mayrequire one or more parameters (e.g. amount/composition/flow rate ofdrilling fluid, power applied to drill bit 101, RPM, WOB, etc.) to bemodified for optimum drilling of the new formation type. Further, asexplained above with respect to FIGS. 7C and 7D, an increase intemperature may indicate wear of one or more cutting elements 128.Accordingly, the drill bit 101 may be replaced or modified in response.For instance, the design or configuration of cutting elements 128 may bemodified based on the temperature measurements of one or more cuttingelements 128 during drilling to improve the efficacy of the cuttingelements. In addition, the temperature of one or more cutting elements128 during drilling may also be used to validate or invalidate thearrangement of nozzles 156 on a bit body. For example, if thetemperature of a cutting element in the cone zone is higher than that ofa cutting element in the nose or gage zones, then the orientation of oneor more nozzles in the cone zone may be adjusted or the number ofnozzles may be increased to provide an improved flow pattern for thedrilling fluid over the cutting elements in the cone zone. If notemperature change is detected at step 808, however, the method moves tostep 812 where drilling continues without any modification to drillingparameters.

Modifications, additions, or omissions may be made to method 800 withoutdeparting from the scope of the present disclosure. For example, anynumber of other drilling characteristics (e.g., chemical composition ofthe formation (e.g. identity and concentration in total or of individualcomponents), formation fluid content (e.g., oil, gas, and/or brines),lithology of the formation (e.g. the concentration ratio of shale,sandstone, limestone and dolomite, the amount of sand, grain size in theformation, etc.), impurity content, pH, viscosity, density, strength,total dissolved solids, salt content, porosity, opacity, bacteriacontent, combinations thereof, and the like) may be determined whilealso determining temperature measurements of cutting elements 128. Inaddition, temperature measurements may be taken from any portion of thedrilling tool and/or formation, in addition to or in lieu of cuttingelements 128. Further, other opto-analytical devices 300 may analyzeproperties of cutting element 128 other than temperature, while thetemperature of the cutting element is being monitored.

An opto-analytical device 300 may also be configured to determinetorsion (also known as windup) of a drill string. FIG. 9 illustrates anexample configuration of BHA 120 including opto-analytical devices 300 aand 300 b configured to determine torsion of the drill string associatedwith BHA 120. In some embodiments, a processing unit of opto-analyticaldevice 300 may be configured to determine and store the amount oftorsion as a function of time in a computer-readable medium to allow forretrieval of the data at a later time. In the same or alternativeembodiments, processing unit 308 may be configured to transmit thetorsion determinations during drilling operations via any suitable MWDsystem.

The torsion or windup of the drilling tool may be measured byrecognizing changes in rotational velocity of the drill bit, and bymatching up reamer data to determine the amount of torque present in thedrill strip. The combination of tool phase and a real timecomposition/porosity map can be used to locate the position of thedrilling tool in the formation. Opto-analytical device 300 may sense anidentifiable feature in the formation as the tool rotates therebyproviding an extremely accurate measurement of rotational velocity ofthe bit. In some embodiments, the identifiable feature in the formationmay be a line or gouge running vertically on the wellbore, and may benaturally occurring or may be placed in the wellbore by a drillingoperator. In other embodiments, the identifiable feature in theformation may be some compositional change in the formation such asfracture plane or bedding plane. By measuring the amount of time betweendetections of the identifiable feature, an operator can see the bitspeed up or slow down, such as for instance, in response to variousformation conditions encountered. Assuming constant power to the tool, aslow down in rotational velocity may indicate a harder rock, and thusincreased torque on the bit and torsion of the drilling tool.

In certain embodiments, two or more opto-analytical devices 300 may beseparated by a distance along the vertical length of the drilling tool,allowing the detection of a radial offset between the two sensors. Thisoffset may be determined based on the detections of the identifiablefeature in the formation described above. Alternatively, the offset maybe determined based on the position of the two sensors with respect toone or more points on the drilling tool. Based on the determined offset,the distance between the sensors, the material properties of the tool,cross sectional dimensions of the wellbore, or other factors, the amountof torsion in the drilling tool may be determined. Since there aredynamic and physical limits to the amount of torsion that can betolerated in a drilling system, drilling may then be slowed or stoppedwhen high amounts of torsion are detected, thereby avoiding any negativeconsequences such as torsional locking of the bit (i.e., sticking in theformation), sudden releases of the torsional energy in the drill,unwinding of the pipe joint, tearing of the drill pipe, etc.

Modifications, additions, or omissions may be made to FIG. 9 withoutdeparting from the scope of the present disclosure. For example, theillustrated embodiment depicts drill bit 101 and reamer 902 integratedwith opto-analytical devices 300 a and 300 b, respectively, to determinetorsion of the drilling tool. However, any combination of drill bit 101,reamer 902, hole enlarger 904 and/or stabilizer 906 (or any othersuitable drilling tool) may include one or more opto-analytical devices300 to determine torsion. Furthermore, opto-analytical device 300 may beconfigured to detect any number of other drilling characteristics (e.g.,chemical composition of the formation (e.g. identity and concentrationin total or of individual components), formation fluid content (e.g.,oil, gas, and/or brines), lithology of the formation (e.g. theconcentration ratio of shale, sandstone, limestone and dolomite, theamount of sand, grain size in the formation, etc.), impurity content,pH, viscosity, density, strength, total dissolved solids, salt content,porosity, opacity, bacteria content, combinations thereof, and the like)while also determining torsion.

FIG. 10 illustrates an example method 1000 for determining torsion of adrilling tool in accordance with some embodiments of the presentdisclosure. Method 1000 may be performed by any suitable, system,apparatus, or device. In the illustrated embodiment, method 1000 may beperformed using opto-analytical device 300 described with respect toFIG. 9.

Method 1000 may start and at step 1002, drill bit 101 may form awellbore by drilling into a geological formation. The method proceeds tostep 1004, where opto-analytical device 300 directs electromagneticradiation toward an object (e.g., the wall of a wellbore 114). At step1006, opto-analytical device 300 mounted on a drilling tool (e.g. adrill bit, a reamer, a stabilizer, a hole enlarger, etc.) receiveselectromagnetic radiation reflected from a wellbore. Then, at step 1008,opto-analytical device 300 detects an identifiable feature in theobject. For instance, the identifiable feature in the object may be aline or gouge running vertically on the wellbore, and may be naturallyoccurring or placed in the wellbore by a drilling operator. In otherembodiments, the identifiable feature in the formation may be somecompositional change in the formation such as fracture plane or beddingplane. In particular embodiments, the identifiable feature may bedetected based on the detection of a deviation in the electromagneticradiation received at a point in time, and may include peaks/spikes orvalleys/dips in the amount of radiation being received at a particularpoint in time.

At step 1010, opto-analytical device 300 determines a torsion in thedrilling tool. This may be accomplished, for example, by determining avelocity of the drill bit over time based on the period of thedeviations detected in the received electromagnetic radiation. This willprovide an observed velocity over time. Based on changes in the velocityover time, the opto-analytical device may determine an amount of torsionin the drill bit at step 1010. As another example, two or moreopto-analytical devices 300 may be separated by a distance along thevertical length of the drilling tool, allowing the detection of a radialoffset between the two sensors, as described above. Based on thedetermined offset, the distance between the sensors, the materialproperties of the tool, the cross sectional dimensions of the wellbore,and/or other factors, the amount of torsion in the drilling tool may bedetermined. This may assist the operator in determining, for example,whether the drill bit is twisting or turning in the wellbore, and mayallow the operator to make one or more modifications at step 1012. Forinstance, the operator may increase or reduce the amount of power to thedrill tool, add or remove WOB, add or remove drilling fluid, change thechemistry of the drilling fluid, or stop the drilling entirely based onthe determined amount of torsion.

Modifications, additions, or omissions may be made to FIG. 10 withoutdeparting from the scope of the present disclosure. For example, anynumber of other drilling characteristics (e.g., chemical composition ofthe formation (e.g. identity and concentration in total or of individualcomponents), formation fluid content (e.g., oil, gas, and/or brines),lithology of the formation (e.g. the concentration ratio of shale,sandstone, limestone and dolomite, the amount of sand, grain size in theformation, etc.), impurity content, pH, viscosity, density, strength,total dissolved solids, salt content, porosity, opacity, bacteriacontent, combinations thereof, and the like) may be determined whilealso determining torsion. Another performance indicator of a drillingtool that may be measured by opto-analytical device 300 may be thedistance or gap between, for example, an object on the drilling tool(e.g., a cutting element, an impact arrestor, a nozzle, a blade, the bitbody, etc) and another object in the wellbore (e.g., the side wall ofthe wellbore). In some embodiments, the gap between an object on thedrill bit and an object in the wellbore may indicate bit whirl, bitwalk, worn cutting elements, vibration of a bit, and/or tilt of a bit.As such, it may be advantageous to monitor the gap between the object onthe drill bit and the object in the wellbore to determine if bit whirl(i.e., movements of the bit away from its rotational axis), bit walk(i.e., the lateral movement of the bit as drilling progresses overtime), worn cutting elements, vibration of a bit, and/or tilt of a bitis present. FIG. 11 illustrates an example embodiment of a gap sensor1100 configured to determine the gap between objects using anopto-analytical device 300, according to some embodiments of the presentdisclosure.

Gap sensor 1100 may include electromagnetic radiation source 406configured to direct electromagnetic radiation toward object 1102 (e.g.,a wall of a wellbore, drilling fluid cake, etc.) such that theelectromagnetic radiation reflects off of object 1102 towardopto-analytical device 300. Gap sensor 1100 may be located in one ormore channels of drill bit 101, in one or more windows 401 of drill bit,on one or more cutting elements 128 of drill bit 101, on one or moreDOCCs 129 of drill bit 101, on one or more blades 126 of drill bit 101,in one or more nozzles 156 of drill bit 101, in fluid flow paths 240 ofdrill bit 101, on shank 152 of drill bit 101, a reamer, a stabilizer, orany other similar location for determining the gap between drill bit 101and object 1102. Processing unit 308 of opto-analytical device 300 ofFIG. 11 may be configured to determine the distance between the objectand gap sensor 1100 based on reflected electromagnetic radiation fromobject 1102. Because the intensity of the reflected electromagneticradiation received is based in large part by the inverse square law oflight, the distance may be determined based on the ratio of therespective intensities of the electromagnetic radiation directed towardobject 1102 and the electromagnetic radiation reflected back from object1102. Alternatively, in other embodiments, the gap may be determinedwhen detector 306 of opto-analytical device 300 includes a splitdetector, quad detector, array detector, or imaging device. In suchembodiments, the gap may be encoded in the electromagnetic radiationdetected by the various detector sub-elements, and may be determinedthrough certain signal processing techniques. For example, in someembodiments, the optical train can be configured so that the gap isrelated to difference between sub-elements while the characteristicsignal is obtained from the sum of the sub elements. In otherembodiments, the gap signal may be derived from a more complexrelationship between the subelements (e.g., in a quad detector,subelement 1 plus subelement 2 minus subelement 3 minus subelement 4) inparallel with detection of the characteristic signal which in general isobtained by the sum of the sub-element signals.

Processing unit 308 of opto-analytical device 300 of gap sensor 1100 maybe configured to store the gap measurements as a function of time in acomputer-readable storage medium such that the gap measurements may beretrieved at a later time after drill bit 101 has been removed from awellbore (e.g., wellbore 114 as illustrated in FIG. 1). In the same oralternative embodiments, processing unit 308 may be configured totransmit the gap measurements to the well site while drill bit 101 is inthe wellbore via any suitable MWD system.

The gap as measured by gap sensor 1100 may be used to determine anynumber of drilling characteristics. For example, one or more gap sensors1100 may be used to determine bit motion, including, but not limited to,bit whirl, bit walk and bit tilt.

Additionally, one or more gap sensors 1100 may be used to determine thedepth of cut of cutting elements and/or wear of cutting elements. Forexample, three or more gap sensors may be mounted circumferentially on adrill bit to estimate the diameter of the hole drilled by the drill bit.An oversized hole may be due to bit wear, downhole vibration, and/orunexpected tilt angle of downhole motor. Likewise, a change in thesymmetry of the hole may raise issues for future drilling activitiessuch as laying casing in the hole or for changing drilling direction. Inaddition, the determined gap may be used to calculate the volume of thehole, which is a vital calculation for drilling operation design. Suchcalculations are used, for example, in determining drilling fluidcirculation volume and cementing operation parameters.

Modifications, additions, or omissions may be made to gap sensor 1100without departing from the scope of the present disclosure. For example,opto-analytical device 300 of gap sensor 1100 may be configured todetect any number of other drilling characteristics (e.g., chemicalcomposition of the formation (e.g. identity and concentration in totalor of individual components), formation fluid content (e.g., oil, gas,and/or brines), lithology of the formation (e.g. the concentration ratioof shale, sandstone, limestone and dolomite, the amount of sand, grainsize in the formation, etc.), impurity content, pH, viscosity, density,strength, total dissolved solids, salt content, porosity, opacity,bacteria content, combinations thereof, and the like) while alsodetermining gap measurements.

Gap sensors 1100 may be configured to determine the bit whirl and bitwalk of a drill bit in a wellbore. FIGS. 12A-12C illustrate an exampleof bit whirl of drill bit 101 in wellbore 114, according to someembodiments of the present disclosure. In FIG. 12A, drill bit 101 mayrotate around its center (Ob) at an angular radian frequency (ω).Additionally, in some instances, bit center Ob may whirl around thecenter of wellbore 114 (Oh) at a whirl radian frequency (Ω). The radiusof the bit whirl (ΔR) may be expressed as the distance between the drillbit center (Ob) and the wellbore center (Oh). Points A, B and C, ofdrill bit 101 may be points on the bit body of drill bit 101 (e.g., onthe gage pad of drill bit 101) and points A1, B1, and C1 may points onthe wall of wellbore 114 at a time t that correspond with points A, B,and C, respectively. In the present embodiment, drill bit 101 mayinclude gap sensor 1100 at each of points A, B, and C to determine thegap between points A and A1 (AA1), points B and B1 (BB1) and points Cand C1 (CC1) respectively.

The coordinates of points A1, B1, and C1 in a Cartesian coordinatesystem with an x-axis (Xb) and a y-axis (Yb) intersecting at the centerof drill bit 101 (Ob) may be expressed by the following equations:

X _(A1)=(Rb+AA1) cos(αa), Y _(A1)=(Rb+AA1) sin(αa);

X _(B1)=(Rb+BB1) cos(αb), Y _(B1)=(Rb+BB1) sin(αb);

X _(C1)=(Rb+CC1) cos(αc), Y _(C1)=(Rb+CC1) sin(αc);

Where Rb is the radius of drill bit 101 and αa, αb and αc are the anglesof points A, B, and C with respect to axis Xb (αa and αb are expresslyshown in FIG. 12).

If it is assumed that wellbore 114 is substantially circular, then thecoordinates of points of A1(X_(A1), Y_(A1)), B1(X_(B1), Y_(B1)) andC1(X_(C1), Y_(C1)) obtained above may be located on the circle. Thecenter coordinates (Xo, Yo) and the radius Rh of the circle may bedetermined by solving the following equations:

${{\begin{matrix}{2\; {XA}\; 1} & {2{YA}\; 1} & {- 1} \\{2\; {XB}\; 1} & {2{YB}\; 1} & {- 1} \\{2\; {XC}\; 1} & {2{YC}\; 1} & {- 1}\end{matrix}}\begin{Bmatrix}{Xo} \\{Yo} \\q\end{Bmatrix}} = \begin{Bmatrix}{{{XA}\; 1^{2}} + {{YA}\; 1^{2}}} \\{{{XB}\; 1^{2}} + {{YB}\; 1^{2}}} \\{{{XC}\; 1^{2}} + {{YC}\; 1^{2}}}\end{Bmatrix}$

Where the hole radius Rh may be expressed as:

Rh={square root over (Xo ² +Yo ² −q)}

and the whirl radius may be expressed as:

ΔR={square root over (Xo ² +Yo ²)}

Additionally, the whirl frequency of drill bit 101 may be obtained byplotting the trajectory of the center of drill bit 101 in the XY planeof a coordinate system with an x-axis (Xh) and y-axis (Yh) intersectingat the center of wellbore 114 (Oh) at time t where: the x-coordinate ofOb with respect to Xh equals Xo(t) and the y-coordinate of Ob withrespect to Yh equals Yo(t). The value of Xo(t) and Yo(t) may be obtainedby solving the above equation at time instant t.

FIG. 12B illustrates an example plot of Xo of the center of drill bit101 (Ob) with respect to time. The whirl frequency (Ω) may be determinedbased on the period (Δt) of the wave of the plot of FIG. 12B asexpressed by the equations below.

${\Omega \; \Delta \; t} = {{2\; \pi \mspace{14mu} {or}\mspace{14mu} \Omega} = \frac{2\; \pi}{\Delta \; t}}$

The whirl frequency (Ω) of drill bit 101 may also be determined byperforming a Fast Fourier Transform (FFT) on either Xo(t) or Yo(t).

The bit angular rotational frequency (Ω) may be obtained by plotting thedistance of AA1 (or BB1 or CC1) as a function of time. FIG. 12Cillustrates an example plot of AA1 as a function of time. In FIG. 12C,the bit angular rotational frequency (ω) may be determined based on theperiod (Δt) of the wave of the plot of FIG. 12C as expressed by theequations below.

${\omega \; \Delta \; t} = {{2\; \pi \mspace{14mu} {or}\mspace{14mu} \omega} = \frac{2\; \pi}{\Delta \; t}}$

Performing an FFT on either AA1(t) or BB1(t) or CC1(t) may also resultin obtaining the bit rotational frequency (ω) of drill bit 101.

Accordingly, a plurality of gap sensors 1100 including opto-analyticaldevices 300 may be configured to determine and record the whirl of drillbit 101 in accordance with some embodiments of the present disclosure.The whirl of drill bit 101 as measured and determined using gap sensors1100 may be used to improve the design of drill bit 101 to decreasewhirl. For example, several anti-whirl technologies, includinglow-friction pads (as described in U.S. Pat. No. 4,932,484 and herebyincorporated by reference in its entirety), and track-loc cutterarrangement (as described in U.S. Pat. No. 5,265,685 and herebyincorporated by reference in its entirety) may be used to avoid bitwhirl. If whirl is detected during drilling, an operator may decreasebit rotational speed and/or increase weight on bit in order to avoidwhirl. Additionally, as mentioned above, opto-analytical devices 300 ofgap sensors 1100 may be configured to detect, determine and record anynumber of other drilling characteristics such as properties of theformation being drilled (e.g., chemical composition, rock strength,plasticity, porosity, etc.) Therefore, in some embodiments, formationcharacteristics may be correlated with the detected amount of bit whirlto determine which formations may cause the most or least whirl of drillbit 101.

Additionally, the trajectory of the center of drill bit 101 (Ob) in theXhYh plane may be determined by plotting the x and y coordinates of Obat different times t in the XhYh plane (Xo(t) and Yo(t), respectively).The locations of the points ((Xo(ti), Yo(ti)) in the XhYh plane mayaccordingly indicate bit walk of drill bit 101. FIG. 12D illustratesexample plots 1202 and 1204 of points ((Xo(ti), Yo(ti)) that indicatethe bit walk of two drill bits 101. Plot 1202 indicates a trajectory ofthe center of the associated drill bit 101 that is up and to the left,thus, indicating that the associated drill bit 101 may walk up and tothe left with respect to the XhYh plane. In contrast, plot 1204indicates a trajectory of the center of the associated drill bit that isup and to the right, thus, indicating that the associated drill bit 101may walk up and to the right, with respect to the XhYh plane. Plots 1202and 1204 are merely examples of bit walk and a drill bit 101 may walk inany number of directions.

Accordingly, a plurality of gap sensors 1100 including opto-analyticaldevices 300 may be configured to determine and record the bit walk of adrill bit 101 in accordance with some embodiments of the presentdisclosure. The bit walk of the drill bit 101 as measured and determinedusing gap sensors 1100 may be used to improve the design of drill bit101 to decrease the walk of drill bit 101. For example, if gap sensors1100 determine that the bit walks left, a deep cone profile may beneeded to reduce the walk left tendency. Additionally, a small gauge padmay help to reduce bit walk left. Conversely, if gap sensors 1100determine that the bit walks right, a shallower cone profile and/or alarger gage pad may be needed to reduce the walk right tendency.Furthermore, the bit walk of the drill bit 101 as measured anddetermined using gap sensors 1100 may be used to guide the rotarysteerable system to change drilling azimuth direction to follow thedesired drilling path. Additionally, as mentioned above, theopto-analytical devices 300 of gap sensors 1100 may be configured todetect, determine and record any number of other drillingcharacteristics such as properties of the formation being drilled (e.g.,chemical composition, rock strength, plasticity, porosity, etc.)Therefore, in some embodiments, formation properties may be correlatedwith bit tilt to determine which formations may cause the most or leastbit walk of drill bit 101.

Modifications, additions, or omissions may be made to FIGS. 12A-12Dwithout departing from the scope of the present disclosure. For example,the coordinate systems used and their respective orientations are forillustrative purposes only, any suitable coordinate system may be used.Additionally, the equations used to determine bit whirl and bit walkusing the gap between a drill bit and wall of a wellbore are forillustrative purposes and any other suitable equation or expression maybe used to determine bit whirl and bit walk. Additionally, as mentionedabove, the opto-analytical devices of gap sensors may be configured todetect any number of other drilling characteristics (e.g., chemicalcomposition of the formation (e.g. identity and concentration in totalor of individual components), formation fluid content (e.g., oil, gas,and/or brines), lithology of the formation (e.g. the concentration ratioof shale, sandstone, limestone and dolomite, the amount of sand, grainsize in the formation, etc.), impurity content, pH, viscosity, density,strength, total dissolved solids, salt content, porosity, opacity,bacteria content, combinations thereof, and the like) while also beingused to determine bit walk and/or bit whirl. Accordingly, bit walkand/or bit whirl may be correlated with other properties of theformation being drilled into.

Gap sensors 1100 may also be configured to determine the tilt andtilting motion of drill bit 101 in wellbore 114. FIG. 13A illustrates across-sectional view of an example configuration of drill bit 101including gap sensors 1100 a and 1100 b configured such that tilt andtilting motion of drill bit 101 may be determined, according to someembodiments of the present disclosure. In the illustrated embodiment,gap sensors 1100 a and 1100 b may be placed at different elevations(with respect to the rotational axis of drill bit 101) on a gage pad ofblade 126 of drill bit 101.

Gap sensors 1100 a and 1100 b may be configured to determine thedistance between the gage pad at their respective locations and wall1302 of wellbore 114. The distance between gap sensors 1100 a and 1100 band wall 1302 are indicated as AA and AB, respectively, in FIG. 13A. Thedifference between the values of AA and AB represent the amount of tiltof drill bit 101 with respect to wall 1302 of wellbore 114. For example,the tilt angle of drill bit 101 at a given time t may be determinedbased on the difference between AA and AB at that time t and thedistance between gap sensors 1100 a and 1100 b with respect to therotational axis of drill bit 101 (L), as indicated by the expressionbelow:

β=atan((ΔA−ΔB)/L)

Plots of AA and AB with respect to time may also indicate the tiltingmotion of drill bit 101. FIG. 13B illustrates example plots 1304 and1306 of AA and AB, respectively, with respect to time.

Accordingly, a plurality of gap sensors 1100 including opto-analyticaldevices 300 may be configured to determine and record the bit tilt ofdrill bit 101 in accordance with some embodiments of the presentdisclosure. The bit tilt of drill bit 101 as measured and determinedusing gap sensors 1100 may be used to improve the design of drill bit101 to decrease the interaction between gage pad and the wall ofwellbore 114 to improve drilling efficiency. In other embodiments, suchas directional drilling, where the tilt may indicate a desired change indirection of drill bit 101, the bit tilt may indicate the degree inwhich drill bit 101 is changing direction. Therefore, modifications maybe made to drill bit 101 and/or the associated steering mechanism basedon the tilt data to improve the steerability of drill bit 101 duringdirectional drilling. Additionally, as mentioned above, opto-analyticaldevices 300 of gap sensors 1100 may be configured to detect, determineand record any number of other drilling characteristics such asproperties of the formation being drilled (e.g., chemical composition,rock strength, plasticity, porosity, etc.) Therefore, in someembodiments, formation properties may be correlated with bit tilt todetermine which formations may cause the most or least tilt of drill bit101.

Modifications, additions, or omissions may be made to FIGS. 13A and 13Bwithout departing from the scope of the present disclosure. For examplethe actual location and configuration of gap sensors 1100 a and 1100 bon a drill bit 101 may vary. In addition, the number of gap sensors 1100of a drill bit 101 configured to determine the tilt of drill bit 101 mayvary. Furthermore, although the above description is given with respectto a drill bit 101, gap sensors 1100 may be configured to determine thetilt of any other drilling tool, as applicable. Additionally,opto-analytical device 300 of gap sensor 1100 may be configured todetect any number of other drilling characteristics (e.g., chemicalcomposition of the formation (e.g. identity and concentration in totalor of individual components), formation fluid content (e.g., oil, gas,and/or brines), lithology of the formation (e.g. the concentration ratioof shale, sandstone, limestone and dolomite, the amount of sand, grainsize in the formation, etc.), impurity content, pH, viscosity, density,strength, total dissolved solids, salt content, porosity, opacity,bacteria content, combinations thereof, and the like) while alsodetermining tilt of a drill bit.

Another performance indicator of a drilling tool that may be measured byopto-analytical device 300 may be the depth of cut of a cutting elementin a formation. In some embodiments, a decreased gap between a portionof a blade 126 and the formation may indicate wear or decreased rate ofpenetration (ROP) into the formation. As such, it may be advantageous tomonitor the gap between a blade 126 and the formation to determine ifcutting elements are worn or if ROP has changed, and possibly modify thedrilling parameters (e.g., power to the tool, WOB, RPM, etc.) to achieveoptimal ROP. A gap sensor 1100 may also be configured to determine thedepth of cut of a cutting element in a formation. FIG. 14 illustrates anexample configuration of drill bit 101 including gap sensor 1100configured to detect the depth of cut of a cutting element 128,according to some embodiments of the present disclosure. In theillustrated embodiment, gap sensor 1100 may be placed at the base ofblade 126 that includes cutting element 128. Gap sensor 1100 may beplaced in front of cutting element 128 in the direction of rotation ofdrill bit 101 and may be configured to measure the distance (parallel tothe rotational axis of drill bit 101) between the base of blade 126 andformation 1402 (illustrated as distance D). The distance (parallel tothe rotational axis of drill bit 101) between gap sensor 1100 and thetip of cutting element 128 (illustrated as distance D0 in FIG. 14) maybe a known parameter of drill bit 101.

The depth of cut of the cutting element 128 (Δc) may be determined bytaking the difference between D and D₀ as expressed by the followingequation:

Δc=D ₀ −D

In some embodiments, a processing unit of an opto-analytical device(e.g., opto-analytical device illustrated in FIG. 3) of gap sensor 1100may be configured to determine the depth of cut and store the depth ofcut as a function of time in a computer-readable medium to allow forretrieval of the data at a later time. In the same or alternativeembodiments, the processing unit 308 may be configured to transmit thedepth of cut determinations during drilling operations via any suitableMWD system. Additionally, in some embodiments, the processing unit maybe configured to determine, store and/or transmit the distance D and thedepth of cut may be determined using any other suitable, system,apparatus or device based on the measured D and known D0.

The depth of cut may be used to determine other drillingcharacteristics. For example, the ROP of drill bit 101 may be related tothe depth of cut of cutting elements 128 and the revolutions per minute(RPM) of the drill bit 101 as expressed by the equation below:

ROP=5*RPM*Δc

Accordingly, one or more gap sensors 1100 including opto-analyticaldevices 300 may be configured to determine and record the depth of cutof one or more cutting elements 128 of drill bit 101 in accordance withsome embodiments of the present disclosure. The depth of cut of cuttingelements 128 as measured and determined using gap sensors 1100 may alsobe used to improve the design of drill bit 101 and cutting elements 128.For example, the actual depth of cut of cutting elements 128 duringdrilling may be used to verify the effectiveness of the DOCCs and toupdate the design of drill bit 101. Additionally, as mentioned above,opto-analytical device 300 of gap sensor 1100 may be configured todetect, determine and record any number of other drillingcharacteristics such as properties of the formation being drilled (e.g.,chemical composition, rock strength, plasticity, porosity, etc.)Therefore, in some embodiments, formation properties may be correlatedwith depth of cut to determine how different formation properties mayaffect the depth of cut.

Modifications, additions, or omissions may be made to FIG. 14 withoutdeparting from the scope of the present disclosure. For example theactual location and configuration of gap sensor 1100 and cutting element128 of FIG. 14 may vary. In addition, the number of gap sensors 1100 ofa drill bit 101 each configured to determine the depth of cut of anassociated cutting element 128 may vary. Furthermore, although the abovedescription is given with respect to a drill bit 101, a gap sensor 1100may be configured to determine the depth of cut of cutting elements ofany other drilling tool.

Additionally, opto-analytical device 300 of gap sensor 1100 may beconfigured to detect any number of other drilling characteristics (e.g.,chemical composition of the formation (e.g. identity and concentrationin total or of individual components), formation fluid content (e.g.,oil, gas, and/or brines), lithology of the formation (e.g. theconcentration ratio of shale, sandstone, limestone and dolomite, theamount of sand, grain size in the formation, etc.), impurity content,pH, viscosity, density, strength, total dissolved solids, salt content,porosity, opacity, bacteria content, combinations thereof, and the like)while also determining depth of cut measurements.

Another performance indicator of a drilling tool that may be measured byopto-analytical device 300 may be the wear of cutting elements 128. Insome embodiments, an increase in the measured gap may indicate wear ofone or more cutting elements 128. As such, it may be advantageous tomonitor the gap between one or more cutting elements 128 on drill bit101 and an object in the wellbore (e.g., the side wall of the wellbore)to determine if there is increasing wear on cutting elements 128. FIG.15 illustrates an example configuration of a drill bit 101 including gapsensor 1100 configured to detect the wear of a cutting element 128,according to some embodiments of the present disclosure. In theillustrated embodiment, gap sensor 1100 may be disposed on the surfaceof blade 126 that includes cutting element 128. Gap sensor 1100 may beplaced behind the cutting element 128 in the direction of rotation ofdrill bit 101 and may be configured to measure the distance (parallel tothe rotational axis of drill bit 101) between the surface of blade 126and formation 1502 after being cut into by the cutting element 128(illustrated as distance D). As the cutting element 128 wears, thedistance D illustrated in FIG. 15 will get smaller.

In some embodiments, a processing unit (e.g., processing unit 308 ofFIG. 3) of the opto-analytical device (e.g., opto-analytical device 300of FIG. 3) of gap sensor 1100 may be configured to determine thedistance D and store the distance D as a function of time in acomputer-readable medium to allow for retrieval of the data at a latertime. In the same or alternative embodiments, the processing unit may beconfigured to transmit the distance D to the well site during drillingoperations via any suitable MWD system. Therefore, an analysis ofdistance D may indicate wear of the cutting element 128.

Accordingly, one or more gap sensors 1100 including opto-analyticaldevices may be configured to detect and record data associated with thewear of one or more cutting elements 128. The wear of cutting elements128 as determined based on the data detected and recorded by gap sensors1100 may be used to improve the design of one or more cutting elements128. For example, the wear of the cutting elements may be used to designand locate backup cutting elements and non-cutting elements (e.g.,DOCCs, blades, etc.). The amount of wear of the cutting elements duringdrilling may also be an indicator of when the drill bit will needreplacing. For example, based on the amount of wear over time, anoperator may be able to estimate the amount of time remaining for thecurrent drill bit, or the amount of time a future drill bit will last.Additionally, as mentioned above, an opto-analytical device of gapsensor 1100 may be configured to detect, determine and record any numberof other drilling characteristics such as properties of the formationbeing drilled (e.g., chemical composition, rock strength, plasticity,porosity, etc.) Therefore, in some embodiments, formation properties maybe correlated with cutting element wear to determine how differentformation properties may affect the wear of cutting elements.

Modifications, additions, or omissions may be made to FIG. 15 withoutdeparting from the scope of the present disclosure. For example theactual location and configuration of gap sensor 1100 and cutting element128 of FIG. 15 may vary. Further, the number of gap sensors 1100 of adrill bit 101 each configured to determine the wear of an associatedcutting element 128 may vary. Further, although the above description isgiven with respect to drill bit 101, gap sensor 1100 may be configuredto determine the wear of cutting elements of any other drilling tool.

FIG. 16 illustrates a flow chart of an example method 1600 fordetermining a gap between objects, according to some embodiments of thepresent disclosure. Method 1600 may be performed by any suitable,system, apparatus, or device. In the illustrated embodiment, method 1600may be performed using gap sensor 1100 described with respect to FIG.11.

Method 1600 may start, and at step 1602 gap sensor 1100 mounted on adrilling tool (e.g. a drill bit 101, a reamer, a stabilizer, a holeenlarger, etc.) may direct electromagnetic radiation toward an object(e.g., the wall of a wellbore 114). At step 1604, gap sensor 1100 maydetect the electromagnetic radiation that has been reflected off of anobject such as the wellbore, the formation, the drill bit, or anotherportion of the drilling tool. At step 1606, the gap sensor 1100 maydetermine a distance between the object and the gap sensor 1100 based onthe reflected electromagnetic radiation.

At step 1608, one or more drilling characteristics may be determinedbased on the distance determined at step 1606. For example, bit motionsuch as bit whirl, bit walk and bit tilt may be determined as describedabove with respect to FIGS. 12A-13B. Additionally, the depth of cut andwear of cutting elements may be determined based on the gapmeasurements, as described with respect to FIGS. 14 and 15,respectively.

Furthermore, if at least three gap sensors are mounted circumferentiallyon a drill bit, the diameter of the hole drilled by the bit may beestimated. The actual hole size is usually larger than that of a drillbit, especially in directional drilling using a downhole motor. Anoversized hole may be due to bit wear, downhole vibration, and/orunexpected tilt angle of a downhole motor.

At step 1610, one or more drilling parameters may be modified based onthe determined drilling characteristics. For example, if bit whirl isdetected during drilling, an operator may decrease bit rotational speedand/or increase weight on bit in order to avoid whirl. As anotherexample, if the bit walks, a deeper or shallower cone profile or alarger or smaller gage pad may be needed to reduce the walk tendency.Furthermore, the drilling azimuth direction may be modified byincreasing or decreasing power to the tool, WOB, RPM, etc. in order tofollow the desired drilling path. Additionally, based on a detectedchange in the depth of cut or the diameter of the hole, a drill bit maybe replaced with a new bit as the change may indicate wear of thecutting elements. Accordingly, method 1600 may use a gap sensor 1100that includes an opto-analytical device 300 to determine one or moredrilling characteristics.

Modifications, additions, or omissions may be made to method 1600without departing from the scope of the present disclosure. For example,as mentioned above, an opto-analytical device 300 of a gap sensor 1100may be configured to detect, determine and record any number of otherdrilling characteristics (e.g., chemical composition of the formation(e.g. identity and concentration in total or of individual components),formation fluid content (e.g., oil, gas, and/or brines), lithology ofthe formation (e.g. the concentration ratio of shale, sandstone,limestone and dolomite, the amount of sand, grain size in the formation,etc.), impurity content, pH, viscosity, density, strength, totaldissolved solids, salt content, porosity, opacity, bacteria content,combinations thereof, and the like) while also determining gapmeasurements. Therefore, in some embodiments, formation properties maybe correlated with drilling characteristics associated with gapmeasurements to determine the effect of the formation properties on thedrilling characteristics associated with the gap measurements.

In addition to the above applications, an opto-analytical device 300 mayalso be used as an accelerometer to determine one or more drillingcharacteristics. FIG. 17A illustrates an example embodiment of anaccelerometer 1700 configured to determine acceleration of a drillingtool using an opto-analytical device 300, according to some embodimentsof the present disclosure. Accelerometer 1700 may be integrated with anysuitable drilling tool and in the illustrated embodiment may beintegrated in a cavity 402 of a drill bit 101. In some embodiments, aprocessing unit of opto-analytical device 300 may be configured todetermine and store the acceleration of the drilling tool as a functionof time in a computer-readable medium to allow for retrieval of the dataat a later time. In the same or alternative embodiments, processing unit308 may be configured to transmit the acceleration determinations duringdrilling operations via any suitable MWD system.

Accelerometer 1700 may include an electromagnetic radiation source 406configured to direct electromagnetic radiation 1701 toward anopto-analytical device 300.

Accelerometer 1700 may also include a mass 1702 coupled to a spring 1704having a spring constant K and a damper 1706 having a dampingcoefficient C. When drill bit 101 moves (e.g., vibrates) mass 1702 mayalso move and block at least part of electromagnetic radiation 1701received by an opto-analytical device 300 of FIG. 17A that includes anICE 302, detector 306 and processing unit 308. Therefore, the intensityof electromagnetic radiation 1701 received by ICE 302 of opto-analyticaldevice 300 may vary according to the movement of mass 1702 such that theacceleration of drill bit 101 may be determined based on the variedintensity of electromagnetic radiation 1701 received by opto-analyticaldevice 300 of accelerometer 1700.

As will be appreciated and recognized by one of ordinary skill in theart, the motion of mass 1702 having a mass M may be described asfollows:

M{umlaut over (x)}+C{dot over (x)}+Kx=−M{umlaut over (x)} _(s)

If the natural frequency of accelerometer 1700 (p) as expressed by

$p = \sqrt{\frac{K}{M}}$

is higher than the measured frequency of drill bit 101 (e.g., thevibration frequency of drill bit 101), then the measured x may beproportional to the acceleration of drill bit 101. FIG. 17B illustratesan alternative embodiment of accelerometer 1700 that uses the sameprinciples as described with respect to FIG. 17A, according to someembodiments of the present disclosure.

Modifications, additions, or omissions may be made to FIGS. 17A and 17Bwithout departing from the scope of the present disclosure. For example,although described with respect to a drill bit 101, accelerometer 1700may be integrated with any suitable drilling tool. Additionally,opto-analytical device 300 of accelerometer 1700 may be configured toreceive electromagnetic radiation from channels (not expressly shown)configured to direct the electromagnetic radiation from the formationbeing drilled into to opto-analytical device 300 of accelerometer 1700.Accordingly, opto-analytical device 300 may be configured to detect,determine and record any number of other drilling characteristics (e.g.,chemical composition of the formation (e.g. identity and concentrationin total or of individual components), formation fluid content (e.g.,oil, gas, and/or brines), lithology of the formation (e.g. theconcentration ratio of shale, sandstone, limestone and dolomite, theamount of sand, grain size in the formation, etc.), impurity content,pH, viscosity, density, strength, total dissolved solids, salt content,porosity, opacity, bacteria content, combinations thereof, and the like)while also determining acceleration. Therefore, in some embodiments,formation properties may be correlated with the movement andacceleration (e.g., vibration) of drill bit 101 as measured byaccelerometer 1700.

Accelerometer 1700 may be used to determine any number of drillingcharacteristics. For example, FIG. 18 illustrates an exampleconfiguration of an accelerometer 1700 integrated with a drill bit 101along the rotational axis of the drill bit 101 such that accelerometer1700 may detect axial vibration of drill bit 101, according to someembodiments of the present disclosure. Accelerometer 1700 may also beused to detect drill bit shocks when the magnitude of acceleration isabove a pre-defined level, for example, 50 g.

Modifications, additions, or omissions may be made to FIG. 18 withoutdeparting from the scope of the present disclosure. For example,although described with respect to determining axial vibration of adrill bit 101, accelerometer 1700 may be integrated with any suitabledrilling tool to determine vibrations associated with that drillingtool. Further, accelerometer 1700 may be integrated at any number oflocations of a drilling tool other than at or near the rotational axisto determine vibration of the drilling tool at the any number oflocations. Additionally, opto-analytical device 300 of accelerometer1700 may be configured to receive electromagnetic radiation fromchannels (not expressly shown) configured to direct the electromagneticradiation from the formation being drilled into to opto-analyticaldevice 300 of accelerometer 1700. Accordingly, opto-analytical device300 may be configured to detect, determine and record any number ofother drilling characteristics (e.g., chemical composition of theformation (e.g. identity and concentration in total or of individualcomponents), formation fluid content (e.g., oil, gas, and/or brines),lithology of the formation (e.g. the concentration ratio of shale,sandstone, limestone and dolomite, the amount of sand, grain size in theformation, etc.), impurity content, pH, viscosity, density, strength,total dissolved solids, salt content, porosity, opacity, bacteriacontent, combinations thereof, and the like) while also determiningacceleration. Therefore, in some embodiments, formation properties maybe correlated with the vibration of drill bit 101 (or any other drillingtool) as measured by accelerometer 1700.

Accelerometer 1700 may also be configured to determine the rotationalspeed of a drilling tool. FIG. 19 illustrates an example configurationof accelerometers 1700 a and 1700 b integrated with a drill bit 101 todetermine the rotational speed of the drill bit 101, according to someembodiments of the present disclosure. Accelerometers 1700 a and 1700 bmay be integrated at two opposite ends of the drill bit 101 as depictedin FIG. 19. The measured acceleration at accelerometer 1700 a (Ax1) andaccelerometer 1700 b (Ax2) may be expressed below using the bitcoordinate system (XbYb plane) of

FIG. 12A:

Ax1=−ΔRΩ ² cos(ω−Ω)t−R ₁ω² and Ax2=−ΔRΩ ² cos(ω−Ω)t−R ₁ω²

and

$\omega = {\sqrt{\frac{{{Ax}\; 2} - {{Ax}\; 1}}{2\; R_{1}}}.}$

Where ω is the rotational speed of drill bit 101, Ω is the whirl speedof drill bit 101, ΔR is the whirl radius, and R₁ is the radial distanceof the lateral accelerometer. The bit center acceleration of drill bit101 in the X direction (Ax) (as indicated by the X-axis of FIG. 19) maybe obtained as expressed below:

${Ax} = {\frac{{{Ax}\; 1} + {{Ax}\; 2}}{2} = {{- \Delta}\; R\; \Omega^{2}{\cos \left( {\omega - \Omega} \right)}t}}$

Additionally, if two other accelerometers 1700 are placed on drill bit101 opposite from each other along the Y-axis of FIG. 19 (e.g.,accelerometers 1700 c and 1700 d) the bit center acceleration of drillbit 101 in the Y direction (Ay) (as indicated by the Y-axis of FIG. 19)may be obtained based on the acceleration as measured by accelerometer1700 c (Ay1) and the acceleration as measured by accelerometer 1700 d(Ay2) as expressed below:

${Ay} = {\frac{{{Ay}\; 1} + {{Ay}\; 2}}{2} = {{- \Delta}\; R\; \Omega^{2}{\sin \left( {\omega - \Omega} \right)}t}}$

Based on the bit center accelerations Ax and Ay, an unwrapped phaseangle may be obtained for drill bit 101 as expressed below:

${\varphi (t)} = {{{\arctan \left( \frac{Ay}{Ax} \right)} + \varphi_{0}} = {{\left( {\omega - \Omega} \right)t} + \varphi_{0}}}$$\frac{\varphi}{t} = {\omega - \Omega}$

At any time, t, unwrapped phase angle φ(t) is calculated from bit centeraccelerations Ax and Ay. Therefore, (ω−Ω) may be deduced by performing alinear least square fitting on φ(t), such that when bit rotational speedω is known, the bit whirl speed Ω may be obtained.

Accordingly, a plurality of accelerometers 1700 may be integrated with adrilling tool (e.g., a drill bit 101, a reamer, a stabilizer, a holeenlarger, etc. to determine drilling characteristics such as the whirlspeed of the drilling tool). Three accelerometers 1700 may be mounted ina mutually orthogonal arrangement along the center line of a drillingtool such as drill bit, downhole motor and MWD tool. The axial andlateral accelerations may be used to measure axial and lateral shocks.

Modifications, additions, or omissions may be made to FIG. 19 withoutdeparting from the scope of the present disclosure. For example,although described with respect to determining whirl speed of a drillbit 101, accelerometer 1700 may be integrated with any suitable drillingtool to determine vibrations associated with that drilling tool.Further, accelerometer 1700 may be integrated at any number of locationsof a drilling tool other than at or near the rotational axis todetermine vibration of the drilling tool at the any number of locations.Additionally, opto-analytical device 300 of accelerometer 1700 may beconfigured to receive electromagnetic radiation from channels (notexpressly shown) configured to direct the electromagnetic radiation fromthe formation being drilled into to opto-analytical device 300 ofaccelerometer 1700. Accordingly, opto-analytical device 300 may beconfigured to detect, determine and record any number of other drillingcharacteristics (e.g., chemical composition of the formation (e.g.identity and concentration in total or of individual components),formation fluid content (e.g., oil, gas, and/or brines), lithology ofthe formation (e.g. the concentration ratio of shale, sandstone,limestone and dolomite, the amount of sand, grain size in the formation,etc.), impurity content, pH, viscosity, density, strength, totaldissolved solids, salt content, porosity, opacity, bacteria content,combinations thereof, and the like). Therefore, in some embodiments,formation properties may be correlated with the whirl speed of drill bit101 (or any other drilling tool such as a reamer or stabilizer) asmeasured by accelerometers 1700.

Although the present disclosure has been described with severalembodiments, various changes and modifications may be suggested to oneskilled in the art. For example, although the present disclosuredescribes the configurations of DOCCs with respect to drill bits havingspecific blade configurations, the same principles may be used to reducethe imbalance forces of any suitable drilling tool according to thepresent disclosure. It is intended that the present disclosureencompasses such changes and modifications as fall within the scope ofthe appended claims.

1. A method comprising: drilling a wellbore in a formation with adrilling tool; receiving electromagnetic radiation using anopto-analytical device coupled to the drilling tool; and determiningtorsion associated with drilling the wellbore based on the receivedelectromagnetic radiation.
 2. The method of claim 1, wherein determiningtorsion associated with drilling the wellbore based on the receivedelectromagnetic radiation comprises: detecting a plurality of deviationsin the received electromagnetic radiation indicating an identifiablefeature in the wellbore; determining a velocity of the drilling toolbased on a period between detections of the deviations in the receivedelectromagnetic radiation; and determining deviations in the velocity ofthe drilling tool.
 3. The method of claim 2, wherein the identifiablefeature is a physical feature in the wellbore.
 4. The method of claim 2,wherein the deviations in the received electromagnetic radiationindicating the identifiable feature in the wellbore comprise peaks in anamount of electromagnetic radiation being received by theopto-analytical device at a particular point in time.
 5. The method ofclaim 1, wherein the opto-analytical device comprises a first sensor anda second sensor coupled to the drilling tool, each sensor displacedlongitudinally along the drilling tool with respect to one another, andwherein determining torsion associated with drilling the wellbore basedon the received electromagnetic radiation comprises determining anoffset between the first and second sensors.
 6. The method of claim 5,wherein determining an offset between the first and second sensors isbased on positions of the first and second sensors with respect to anidentifiable feature in the wellbore.
 7. The method of claim 5, whereindetermining an offset between the first and second sensors is based onpositions of the first and second sensors with respect to anidentifiable feature on the drilling tool.
 8. A downhole drilling systemcomprising: a downhole drilling tool configured to drill a wellbore in aformation with a drilling tool; and an opto-analytical device coupled tothe drilling tool configured to: receive electromagnetic radiation; anddetermine torsion associated with drilling the wellbore based on thereceived electromagnetic radiation.
 9. The system of claim 8, whereinthe opto-analytical device configured to determine torsion associatedwith drilling the wellbore based on the received electromagneticradiation is configured to: detect a plurality of deviations in thereceived electromagnetic radiation indicating an identifiable feature inthe wellbore; determine a velocity of the drilling tool based on aperiod between detections of the deviations in the receivedelectromagnetic radiation; and determine deviations in the velocity ofthe drilling tool.
 10. The system of claim 9, wherein the identifiablefeature is a physical feature in the wellbore.
 11. The system of claim9, wherein the deviations in the received electromagnetic radiationindicating the identifiable feature in the wellbore comprise peaks in anamount of electromagnetic radiation being received by theopto-analytical device at a particular point in time.
 12. The system ofclaim 8, wherein the opto-analytical device comprises a first sensor anda second sensor coupled to the drilling tool, each sensor displacedlongitudinally along the drilling tool with respect to one another, andwherein determining torsion associated with drilling the wellbore basedon the received electromagnetic radiation comprises determining anoffset between the first and second sensors.
 13. The system of claim 12,wherein determining an offset between the first and second sensors isbased on positions of the first and second sensors with respect to anidentifiable feature in the wellbore.
 14. The system of claim 12,wherein determining an offset between the first and second sensors isbased on positions of the first and second sensors with respect to anidentifiable feature on the drilling tool.
 15. A drill bit comprising: abit body; a rotational axis about which the bit body rotates; aplurality of blades disposed on the bit body to create a bit face; anopto-analytical device integrated with the bit body, the opto-analyticaldevice configured to: receive electromagnetic radiation; and determinetorsion associated with drilling a wellbore based on the receivedelectromagnetic radiation.
 16. The drill bit of claim 15, wherein theopto-analytical device configured to determine torsion associated withdrilling the wellbore based on the received electromagnetic radiation inconfigured to: detect a plurality of deviations in the receivedelectromagnetic radiation indicating an identifiable feature in thewellbore; determine a velocity of the drill bit based on a periodbetween detections of the deviations in the received electromagneticradiation; and determine deviations in the velocity of the drill bit.17. The drill bit of claim 16, wherein the identifiable feature is aphysical feature in the wellbore.
 18. The drill bit of claim 16, whereinthe deviations in the received electromagnetic radiation indicating anidentifiable feature in the wellbore comprise peaks in an amount ofelectromagnetic radiation being received by the opto-analytical deviceat a particular point in time.
 19. The drill bit of claim 15, whereinthe opto-analytical device comprises a first sensor and a second sensorcoupled to the drill bit, each sensor displaced longitudinally along thedrill bit with respect to one another, and wherein determining torsionassociated with drilling the wellbore based on the receivedelectromagnetic radiation comprises determining an offset between thefirst and second sensors.
 20. The drill bit of claim 19, whereindetermining an offset between the first and second sensors is based onpositions of the first and second sensors with respect to anidentifiable feature in the wellbore.
 21. The drill bit of claim 19,wherein determining an offset between the first and second sensors isbased on positions of the first and second sensors with respect to anidentifiable feature on the drill bit.